Oilfield Technology - November 2020

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Contents 03 Comment

Nov/Dec 2020 Volume 13 Issue 06

25 The devil is in the detail Andreas Hofmann and Willem van Strien, SGS, the Netherlands, discuss new technologies for reservoir characterisation and field and facility health monitoring.

05 World news 10 At the forefront of the energy transition Jessica Brewer and Kyrah McKenzie, Wood Mackenzie, UK, examine how North Sea operators are embracing ambitious projects on the road to net zero.

13 Collaboration’s the name of the game Duncan McAllister, Varel Energy Solutions, USA, and Cody Baranowski, D-Tech Drilling Tools, USA, explain how supplier-to-supplier collaboration contributed to success in a challenging drilling operation.

17 Getting the right placement Fraser Cowie, Jayaneethe Naranasamy, and Stephen Forrester, Gyrodata, explore how gyro while drilling technology can improve wellbore collision risk mitigation and well placement in challenging projects.

29 Built for the corrode ahead Larry Chen, Dr Nihal Obeyesekere, Thusitha Wickramarachchi, and Dr Jonathan Wylde, Clariant Oil Services, USA, analyse high temperature stable corrosion inhibitor development for deepwater applications.

33 Under wraps Jean-Francois Ribet, 3X Engineering, Monaco, recounts the repair of subsea caissons at a North Sea platform, using composite wrapping.

35 Combining data and design Gilberto Gallo, Drillmec, USA, outlines the importance of technology to rig design and improving drilling performance.

39 A sense of what is to come

20 The fine margins of success Cory Langford, Scientific Drilling International, USA, discusses how at-bit gamma ray images and continuous inclination measurements enable pro-active geosteering in tight target windows.

Stian Engebretsen, Aurore Plougoulen, and Lars Anders Ruden, Emerson Automation Solutions, describe an IIoT powered digital metering solution, which couples sensors, multiphase meters and virtual flow metering.

43 All systems are flow Brian Kettner, Badger Meter, USA, highlights the importance of selecting the right flow meter for oil and gas applications.

Front cover Multi-Chem, a Halliburton Service, delivers superior service and chemical applications expertise to maximise asset value for upstream, midstream and downstream customers.

46 Paving new paths in Bremen Jörg Eitler, NETZSCH Pumpen & Systeme GmbH, Germany, highlights a case study in which an electric submersible progressing cavity pump system with a permanent magnet motor was able to convey efficiently and reliably.



50 The only way to P&A Maxim Volkov and Luis Perri, TGT Diagnostics, UK, explain how new advances in through-barrier integrity diagnostics can remove uncertainty and improve success in plug and abandonment and slot recovery operations.

Our team of experts solve traditional oilfield challenges and unique ones by listening first and then responding with collaborative solutions focused on helping customers meet production and cost objectives.

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Editorial Managing Editor: James Little


t the time of writing, at least 59 million Americans were believed to have already voted in the country’s presidential election – a remarkable figure that offers some hope in these uncertain times for democracy. Although COVID-19 has understandably dominated this year’s election cycle, energy policy has also been an important theme in proceedings. On the face of things, continuity, rather than a change in administration, would appear to be of greater benefit to a US upstream industry beleaguered by erratic oil prices, depressed demand, and job losses. Donald Trump’s time in office has seen the rubberstamping of the Keystone XL and Dakota Access pipelines and America superseding Saudi Arabia and Russia to become the largest crude oil producer globally. A key element of his energy platform in the current campaign consists of progressing with plans to sell leases for drilling in sections of Alaska’s Arctic National Wildlife Refuge. Joe Biden, the Democratic candidate, has committed to a US$2 trillion climate plan that would aim to see the US become a net-zero carbon emitter by the middle of the century and have a carbon pollution-free power sector by 2035. A ban on the issuing of new licences on federal land has also been outlined. The corollary of all this, as Biden stated in the final presidential debate, would be an acceleration in the energy transition and a gradual shift away from oil and gas. Biden has, however, ruled out a prohibition on hydraulic fracturing, except on federal land; while this has been a source of friction within his party, it’s a pragmatic move that clearly comes with an eye on winning Pennsylvania, a shale hub that’s also a key swing state. Should Biden fail to secure the 20 Electoral College votes on offer in his home state, the chances of him becoming the 46th president slim significantly. Biden’s proposals have not entirely alienated the upstream industry however. According to the Center for Responsive Politics, as of 16 October he had accepted US$780 000 in donations from oil and gas companies, albeit much less than the US$1.9 million endorsement Trump has received.1 Interestingly, Rystad Energy has posited that a Biden presidency could in fact be of benefit to the industry, at least in the short-term, on the grounds that it raises the likelihood of a price-boosting cessation of the trade war with China. Furthermore, the consultancy’s analysis concludes that a fraccing ban on federal land “would also most likely have a positive impact on oil prices in the short term.”2 It would not be entirely accurate to say that Trump – mercurial at the best of times – has consistently enacted pro-oil measures either. Last month, the president expanded a moratorium on drilling in the Eastern Gulf of Mexico to offshore Florida and North Carolina. In response, the API issued a statement calling the decision “another move in the wrong direction for American energy security.” Regardless of the outcome of the election, the decades spent by both Democratic and Republican administrations in pursuit of hydrocarbon-based energy independence since the 1970s means oil and gas will remain a pivotal element of the country’s energy portfolio for some time to come.

References 1. 2.

Center for Responsive Politics, ‘Oil & Gas: Top Recipients,’ https://www.opensecrets.org/industries/ recips.php?ind=E01++ (16 October 2020). Rystad Energy, ‘US presidents and oil production: A deep dive into Obama and Trump records, Biden’s proposed plan,’ https://www.rystadenergy.com/newsevents/news/press-releases/ us-presidents-and-oil-production-a-deep-dive-into-obama-and-trump-records-bidens-proposedplan/ (25 August 2020).


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November/December 2020 Oilfield Technology | 3

World news Emerson to provide automation technologies for new Caspian Sea platform Emerson has been awarded a US$14 million contract to provide automation technologies for the new Azeri Central East offshore platform in the Caspian Sea, the latest development in the Azeri-Chirag-Deepwater Gunashli oilfield. Emerson will provide its Project Certainty methodologies and digital technologies to help BP bring the project onstream in 2023. Digital twin solutions and cloud engineering services will help accelerate project execution. Emerson’s digital twin solution enables virtual testing and system integration while the platform is being built and provides a simulated environment for platform operators to train. Cloud engineering reduces engineering costs and time by enabling global teams to collaborate and engineer in parallel regardless of location. Emerson will apply its portfolio of automation software and services to help BP achieve greater production and safe operations. This includes the DeltaVTM automation system that controls critical safety functions in addition to wellhead production, drilling and the transfer of oil and gas to the onshore Sangachal Terminal. Wired and wireless networks will connect measurement instruments to monitor pressure, flow, temperature and pipework corrosion. Emerson will also provide all critical control, emergency shutdown and isolation valves, connected by its digital positioning technology.

Petronas awards seismic consortium contract

Karoon acquisition of Baúna field approved

A seismic consortium comprising PGS, TGS and WesternGeco has been awarded a multi-year contract by Petronas to acquire and process up to 105 000 km2 of multi-sensor multi-client 3D data in the Sarawak Basin, offshore Malaysia. The award follows an ongoing campaign by the consortium in the Sabah offshore region of Malaysia, in which over 50 000 km2 of 3D seismic data have been acquired and licensed to support Malaysia licence round and exploration activity. The Sarawak award will enable the consortium to position itself in Malaysian seismic exploration and allow for a multi-phase programme to promote exploration efforts in the prolific Sarawak East Natuna Basin (Deepwater North Luconia and West Luconia Province). The consortium is planning the initial phases and is engaging with the industry to secure prefunding ahead of planned acquisition, covering both open blocks and areas of existing farm-in opportunities.

Karoon Energy has announced that the Board of Directors of Brazil’s Agência Nacional do Petróleo, Gás Natural e Biocombustíveis (ANP) has approved the assignment of the rights and obligations under Concession Contract BM-S-40 related to the Baúna field. Once written confirmation of the approval of the sale of the field by Petrobras is issued, a further condition precedent to transaction close under the Baúna sale and purchase agreement and the last outstanding regulatory condition precedent will be satisified. The approval follows the issue of new environmental operational licences by the Brazilian Institute of the Environment and Renewable Natural Resources (IBAMA). Transaction close still remains subject to certain conditions precedent, including FPSO charter assignment. In relation to the FPSO charter assignment, Karoon does not consider that this will delay transaction close.

In brief Egypt BP has announced the start of production from the Qattameya gas field in the North Damietta offshore concession. The field, located approximately 45 km west of the Ha’py platform, is expected to produce up to 50 million ft3/d of gas. It is tied back to the Ha’py and Tuart field development via a new 50 km pipeline and is also connected to their existing subsea utilities via a 50 km umbilical. BP holds 100% equity in the North Damietta offshore concession.

UK Archer has secured a two-year contract extension with a major North Sea operator for the provision of platform drilling operations and maintenance services on seven UK North Sea installations. The extension will commence 1 November 2020 in direct continuation of the current contract. Over the next two years Archer will continue to deliver drilling operations, maintenance and intervention support services including the provision of well services and rental equipment.

Norway TechnipFMC has been awarded an EPCI contract by Equinor for the Breidablikk Pipelay, including option for the subsea installation scope located in the area close to the Grane field, North Sea. The Breidablikk project is a tie-back to the existing Grane platform. TechnipFMC’s scope includes provision of flexible jumpers and rigid pipelines as well as pipeline installation work. The Breidablikk development is subject to final approval by the Norwegian authorities.

November/December 2020 Oilfield Technology | 5

World news Diary dates 9 – 12 November 2020 ADIPEC 2020 Online adipec.com/virtual-2020-home/

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

8 – 11 December 2020 EAGE Annual Conference Online Online eage.eventsair.com/annual-conferenceonline/

13 – 16 September 2021 Gastech Singapore gastechevent.com/ To stay informed about the status of industry events and potential postponements or cancellations of events due to COVID-19, visit Oilfield Technology’s events listing page: www.oilfieldtechnology.com/events/

Web news highlights Ì Ì Ì Ì

Cenovus Energy and Husky Energy agree merger Peterson and OneSubsea agree logistics contract ConocoPhillips to acquire Concho Resources Dvalin field given start-up approval

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


6 | Oilfield Technology November/December 2020

Maersk Drilling awarded three-well contract

TGS starts coring project offshore Nigeria

Maersk Drilling has been awarded a three-well contract from Total E&P Angola for the 7th generation drillship Maersk Voyager, which will be employed to drill development wells in Angola’s Block 17. The three-well contract has an estimated duration of 140 days, which means that Maersk Voyager is now contracted until 2Q21. The firm value of the three-well contract is approximately US$30 million, including integrated drilling services provided. The two one-well options included in Maersk Voyager’s previously agreed work scope for Total E&P remain. Maersk Voyager is a high-specification ultra-deepwater drillship which was delivered in 2014. It has been operating offshore Africa since 2015 and commenced operations for Total E&P Angola in January this year.

TGS has announced the recommencement of a geochemical coring project offshore Nigeria. The initiative is part of an anomaly targeting programme focusing on the previously completed analysis of multibeam and backscatter data. The survey is being conducted in conjunction with Nigerian joint venture partner TGS-PetroData. Completion is planned for late November. The project covers an area of approximately 82 000 km2 and will incorporate 17 seabed heat flow measurements and 253 seabed cores whose location is based on multibeam and backscatter anomalies. The data is complemented by TGS’ NGRE19 2D seismic data reprocessed last year. Once coring is concluded, geochemistry will be undertaken with final reports ready for industry review in 1Q21.

Shell to use Bentley digital twin platform for deepwater projects Bentley Systems has announced that Shell’s Deepwater business has selected Bentley’s digital twin approach to streamline its capital projects process and accelerate time to first oil. With a plan to deliver several subsea tie-back projects over the next 10 years, Shell Deepwater Projects will accelerate capital project delivery and cut project delivery time by implementing an integrated digital project and engineering environment. The solution spans project conception in the early phase design through to handover. In addition, Bentley has announced that it is providing investment funds to FutureOn, a Norwegian software company supporting deepwater subsea projects, to accelerate going digital within the oil and gas industry. The investment sets the stage for FutureOn and Bentley to deliver digital twin technology required for oil and gas ecosystems to manage and analyse data, integrate with existing systems, provide analytics visibility, and rapidly explore ideas collaboratively. FutureOn builds on more than 20 years of visual engineering experience specifically in the oil and gas subsea domain. The company will combine its field design application (FieldAP) and its API-centric collaboration platform (FieldTwin) with Bentley’s digital twin platform (iTwin) to advance user organisations such as Shell Deepwater. Both FutureOn and Bentley platforms use open web standards to facilitate complex integration and customisation, and the combined offerings are already being implemented in exploration and production workflows for the creation and curation of subsea digital twins.

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World news CGG starts Walker Ridge reimaging programme CGG has announced the start of a new seismic data reimaging programme in the prospective Walker Ridge area, as part of a major reimaging campaign being conducted in the Gulf of Mexico. The Walker Ridge programme covers approximately 300 Outer Continental Shelf (OCS) blocks including two priority areas of significant industry interest. Proprietary imaging technologies will be applied to this programme to unlock the full potential of existing seismic data and provide significant uplift in subsurface imaging. Given recent discoveries and proven production in Walker Ridge, the new programme has received strong industry prefunding from clients actively exploring and drilling for oil and gas within this basin. CGG’s Walker Ridge Wide-Azimuth and StagSeis DEUX surveys will provide input for the project and the reprocessed data will deliver valuable, high-quality imaging throughout the programme with two priority discovery areas being processed on an accelerated schedule. Final products are expected in February 2021 and May 2021 respectively, ahead of the full programme results, which are due out by the end of 2021. The target of CGG’s new programme is the prolific Wilcox formation, which is deformed by thrusts and folds beneath multiple thick salt sheets and shales that have historically been difficult to image. To better define this challenging and complex area, CGG will reprocess existing data with 3D deghosting, 3D SRME and its new velocity modelling technologies, including Time-Lag FWI and FWI Imaging. Preliminary test results show significant uplift in imaging of the subsalt fold-belts and continuity of reflectors within the Eocene and Paleocene exploration targets.

Oceaneering awarded BOP tethering contract Oceaneering International has been awarded a one-year blowout preventer (BOP) tethering services contract offshore Brazil from Petrobras. The scope of work includes data acquisition and real-time riser analysis for dynamic positioning rig operations for up to seven wells in water depths between 150 m and 700 m. Oceaneering will provide eight suction piles as well as 10 wellhead load relief (WLR) tensioners, one monitoring system to be integrated on the BOP, and one suction pile pump to install the suction piles. An anchor handling tug supply (AHTS) vessel will launch and install the suction piles and tensioners. The drilling rig will be used to connect the tensioners to the BOP.

Touchstone makes gas discovery in Trinidad

Wood secures Mariner contract with Equinor

BOSS given funding for AUV project

Touchstone Exploration Inc. has completed drilling the Chinook-1 exploration well on the Ortoire exploration block, onshore in the Republic of Trinidad and Tobago and announced that the well encountered significant hydrocarbon accumulations based on wireline log data. Drilling samples and open hole wireline logs indicated that the Chinook-1 well encountered a significant Herrera turbidite package with a total thickness of 2000 ft containing over 1480 ft of sand. Open hole well logs and drilling samples indicated that these sands contain an aggregate 589 net ft of natural gas pay in three unique thrust sheets. An additional natural gas pay of approximately 20 net ft was encountered in the shallower Cruse formation. The company expects to initiate a comprehensive completion and testing plan to evaluate the economic potential of the hydrocarbon sands in 1Q21. The drilling rig is expected to move to the Cascadura Deep location prior to the end of the month.

Wood has secured a new contract to support Equinor’s operations at the Mariner field in the UK Continental Shelf (UKCS). Wood has entered into a three-year agreement to deliver operations, maintenance, modifications, and offshore services on the Mariner A platform and Mariner B floating storage unit. The agreement, valued at around US$75 million, will run for three years from January 2021 through to 4Q23, with options to extend. Mariner is an offshore development supported by automated drilling and digital twin solutions. The Mariner field is Equinor’s first operated development in the UK North Sea. The contract builds upon Wood’s recent agreements with Equinor on the Kollsnes gas processing facility and Breidablikktie-back development in Norway. The work will be delivered by Wood’s Aberdeen-based onshore and offshore teams.

Blue Ocean Seismic Services (BOSS) has secured a total of £10 million of Series A investment from BP Ventures, Woodside Energy and Blue Ocean Monitoring. The investment will be deployed to continue the development of an autonomous underwater vehicle (AUV) which uses long endurance self-repositioning autonomous underwater nodes to conduct offshore seismic surveys for oil and gas exploration and reservoir optimisation, whilst also identifying and monitoring carbon storage opportunities under the seabed. The technology has been designed to be fully containerised, scalable and modular allowing for deployment to survey locations across the globe. To support the project, the company has established a new corporate head office, laboratory and workshop facility in Farnborough, UK. It is planning to open other offices from next year. All three investors are actively involved in developing the technology.

8 | Oilfield Technology November/December 2020

At the forefront of the energy transition

10 |

Jessica Brewer and Kyrah McKenzie, Wood Mackenzie, UK, examine how North Sea operators are embracing ambitious projects on the road to net zero.


eeting ambitious net zero targets requires drastic action. The upstream sector must change – this is nothing new. It will not be easy, but it is doable. The energy transition offers opportunities for the oil and gas industry, and the North Sea Basin is at the forefront of that change: it has been pushing the boundaries since its inception in the 1970s. What challenges will North Sea operators face on the road to net zero? And where are the opportunities for upstream players to take the lead?

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Drastic action is required – but the momentum is there to drive change Hydrocarbons will remain a crucial part of the energy mix for some time to come, given that the oil and gas industry provides substantial value to North Sea economies. However, drastic action is required to meet net zero targets. North Sea governments have set the course by advancing aggressive decarbonisation agendas; operators must evolve to retain a licence to operate. That must be balanced against the need to deliver a return on investment. Those dynamics are driving North Sea operators to embrace some of the most ambitious decarbonisation initiatives across the global industry.

North Sea leads the way on the road to net zero The North Sea’s upstream sector is at the forefront of the energy transition as new technologies are explored. While there is no single solution, time will deal with some issues as mature infrastructure is decommissioned. In the interim, older platforms can be adapted without huge capital investment through digitalisation and flaring reduction, for example. Carbon capture, use and storage (CCUS) pilot projects are being supported by each of the North Sea governments. The North Sea’s Continental Shelf is a proposed area for carbon storage. Subsurface expertise will help determine the feasible locations. Upstream operators are becoming actively involved in the CCUS value chain. Similarly, feasibility studies are being conducted into green and blue hydrogen. Hydrogen offers opportunities to reuse or extend the life of existing infrastructure, which has a host of benefits. Offshore installations come with an inherent carbon footprint from the manufacturing process. Maximising asset life is advantageous and reduces the risk of stranded pipeline infrastructure assets.

Electrification of offshore platforms is the frontrunner Led by Norway, which has the highest share of electricity produced from renewable sources in Europe, platform

Figure 1. Norwegian emissions OPEX.

12 | Oilfield Technology November/December 2020

electrification has taken off. Emissions from power generation currently account for the largest share of offshore upstream emissions. This is therefore a high-value area to target in order to achieve emissions reduction targets. To date, eight fields in Norway receive power from the Norwegian grid – four of these are platform developments. Further investment is coming; by 2023, 50% of Norway’s liquids and gas production is due to be either fully or partially electrified, with still more to follow. Norway continues to push the technology forward. Equinor’s Hywind Tampen project is an industry first. Sanctioned in 2019 and scheduled to start up by the end of 2022, the project will use eleven 8 MW floating offshore wind turbines to provide 35% of the annual power for the Snorre and Gullfaks platforms.

Rising carbon costs provide a strong incentive for action All North Sea countries participate in the EU Emissions Trading Scheme – designed to help member states limit or reduce greenhouse gas emissions – but Norway goes a step further. Its additional CO2 and NOX taxes act as a strong incentive for operators to reduce emissions. Electrification project returns can compete with traditional upstream projects. For example, Equinor, Lundin Energy and Aker BP’s Utsira High project, which will power 10 fields with electricity from shore and save approximately 1.15 million tpy of CO2, can generate a return greater than 10% under Wood Mackenzie’s base assumptions. However, Norway’s unique carbon tax system is critical to achieving this. In addition, electrification boasts other benefits. Reducing the quantity of gas required to power turbines can allow for higher sales production and/or greater availability of gas for reinjection at oilfields. Increased uptime can be achieved due to the lower risk of equipment breakdown.

There is huge potential, but scale will be key The energy transition could have created an existential crisis for North Sea stakeholders, yet governments and industry are embracing change. The North Sea is retaining its leadership status through technological innovation. The industry cannot afford to stand still. Trial technologies have a common problem: to become economically viable they need to scale. At the same time, the North Sea is competing with global producers, where the energy transition is not quite as high on the agenda. Continued support for pilot projects, and a willingness to adapt, will be critical if the North Sea is to maintain its flagship status.


GAME Duncan McAllister, Varel Energy Solutions, USA, and Cody Baranowski, D-Tech Drilling Tools, USA, explain how supplier-to-supplier collaboration contributed to success in a challenging drilling operation.


ne of the largest challenges within the oil and gas industry has always been communication. Some operators have gone so far as to mandate the use of what is sometimes referred to as the ‘echo effect’, i.e. repeating back the words a person hears from another person they are communicating with, in order to create familiarity. The insatiable drive within all industries, not just the energy sector, to improve communication and collaboration originates from the understanding that the success or failure of goals comes down to communication.

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This is not to say that the quality, reliability, and performance of the tools that are selected for a project do not have a major impact on, for example, reducing the number of bits runs per section: what if performance suffers due to the selection of individual tools without prior consideration of the entire drilling system? The best drill bit for a motor assembly does not always work as effectively in a push-the-bit rotary steerable assembly. The challenge of communication in these scenarios lies in an important aspect that is often overlooked: supplier-to-supplier collaboration. When done correctly it can

bring greater value to the end user and increase the chance of success.

Case study An operator drilling in Oklahoma, US, faced a challenging 8.75 in. intermediate section with high angle tangents. The operator’s aim was to reduce the number of bit trips without sacrificing overall rate of penetration (ROP). Varel Energy Solutions, in coordination with D-Tech Rotary Steerable, worked to balance the design requirements for the lithology and directional requirements of the rotary steerable system. The companies’ steerable teams coordinated with the operator to create a collaborative approach to selecting the right bit for the application. This approach not only achieved the goal over a long period – completing the interval in one run 21 times over a 30 well period – but was successful on the very first run. Offset wells in the same area averaged 1.9 bits per section.

Developing a solution

Figure 1. Example of different directional simulation types inside the DigIT-3D


Figure 2. Survey information highlighting the high tangent angles that were achieved and held in this application.

14 | Oilfield Technology November/December 2020

The target application presented a considerable challenge, not only in terms of decreasing the number of bit runs without sacrificing speed but also achieving directional objectives. The tangent angles on the subject wells ranged from 20˚ to 45˚of inclination. To achieve the directional requirements throughout the interval D-Tech’s engineering team first highlighted the importance of shoulder durability to maintain side cutting capability. By reviewing the rotary steerable tool memory, they were able to identify that the increased cutter size was causing drill string dysfunction. This was visible in the string speed variation in the rotary steerable tool memory. In the case of the smaller cutters, the string speed was more consistent and bottomhole assembly (BHA) rarely entered a state of dysfunction. The 13 mm cutter led to more consistent ROP and a more effective use of energy by the rig and the drill bit. Using the detailed knowledge shared by D-Tech, Varel’s 8.75 in. F613P-F design was selected; most offset designs in the Merge area intermediate sections were 6 blade 16 mm cutters. The use of the 13 mm cutter yielded the added durability that was needed while work was carried out to make sure the aggressiveness would be reduced as little as possible. Although some instantaneous ROP was conceded, it was found that the overall average ROP was able to offset 6 blade 16 mm cutter designs through better shoulder durability and a reduced risk of inducing drilling dysfunctions. Another important aspect of bit selection that was considered for this application was finding the right balance between side cutting capability and hold tendency. Most bit designs that hold their angle well are designed to resist side forces, such as gravity. This means there is a balance that needs to be reached between side cutting capability and hold tendency. To achieve the desired dog leg severity, the bit would need to respond to the side forces from the push-the-bit rotary steerable system but also have a good hold tendency once the tangent angle was reached. To aid in the investigation of achieving this balance Varel’s engineering team used DigIT-3DTM simulation software to analyse a 8.75 in. F613P-F design on the end of a push-the-bit assembly (Figure 1). The software can simulate different directional drilling scenarios as well as different drive systems. The analysis concluded that the gauge pad configuration would contribute to an added hold tendency

when the bit was not under active steering. Maintaining exposure, as well as the right aggressiveness, to the trimmer and shoulder cutters allowed for side cutting to occur when steer force was applied. The combination of these two features working together led to the balance between side cutting capability and hold tendency that the engineering teams were looking for, as shown in Figure 2. A third key factor that also needed to be considered, in order to achieve a successful operation, was cutting profile. Steerability of the bit, or the bit’s side cutting capability, is extremely important. When using a push-the-bit rotary steerable tool having an aggressive shoulder cutting structure is critical. If the shoulder becomes dull during the run the bit will not be able to cut laterally when the tool creates a side force. The shape of the bit face and the bit’s ability to be pushed off axis are also important. For the bit to be pushed off its axis, the entire profile, not just the shoulder, needs to be designed with this intent in mind. Varel can create steerable cutting profiles that allow for the creating of low imbalance cutting structure design. It is often the case that primary focus is placed on the shoulder and gauge pad configuration for rotary steerable bit selection, but the cone cutting structure can influence steerability as well. Bit life in all portions of the profile is critical to the steerability of the

D-Tech tool. It is important that the bit is designed to be durable in the target formation and that its cutting structure can not only withstand the formation but also the additional side force created by the pistons of the rotary steerable in the target application. Collaboration between the bit and rotary steerable company led to the design of a bit that met the needs of the rotary steerable tool and, ultimately, the operator. The bit provided an aggressive 13 mm cutting structure that balanced the durability needed to maintain side cutting with the desired penetration rate. The bit’s ability to maintain a sharp cutting structure as drilling took place allowed the rotary steerable tool to maintain the target steerability throughout multiple formations that have historically been more difficult to steer in. The exposure of the cutter structure was balanced with the gauge pad length and relief to allow for some side cutting while maintaining a hold tendency. The profile was analysed from the cone to the gauge to achieve steerability and a low imbalance cutting structure.

Results Analysis of the 30 well dataset yielded an average bit run of 1.4, average interval of 7819 ft, average hours of 52.5, and an average ROP of 149 ft/hr (Figures 3 and 4). Each of these major metrics also saw little variation throughout the selected group of wells, verifying the consistent performance that was sought by the operator. Analysis of the steerability revealed that the bit provided the rotary steerable tool with consistent steerability and increased yield. Well plans with up to 5˚/100 ft of build were utilised on intermediates that built up to 40˚or more of inclination (Figure 2). The rotary steerable tool was able to build these tangents without issue, maintain angle in the hold section, and drop the inclination out. This result was achieved due to the durability of the drill bit and its ability to drill through tough formations and maintain a sharp cutting structure. The record setting runs displayed in Table 1 were achieved through lower tangent angle.

Figure 3. Drill bit performance dataset from the same 30 wells D-Tech analysed.


Figure 4. Recorded downhole string speed from D-Tech run on 16 mm cutter bit. Table 1. Runs in Mid-Con Merge play, Grady County, Oklahoma, US Record run


Depth in/depth out

Footage drilled




Run 1


1211 ft to 8915 ft

7704 ft


207 ft/hr

8 3/4 in. F613P-F

Run 2


1224 ft to 8876 ft

7652 ft


201 ft/hr

8 3/4 in. F613P-F

16 | Oilfield Technology November/December 2020

Though these forms of strategic collaboration occur throughout the industry, there is considerable room to improve the frequency and willingness to dive deeper. As organisations begin to align their core intent towards generating value, there lies a significant opportunity to progress as an industry – finding greater efficiencies, higher performance gains and a more effective use of capital. The system-matched approach to delivering the right drill bit and drive system is one of many ways to build step-change advancements, not only in drilling wellbores, but also for creating a sustainable marketplace for the industry in the future.

Getting the right Placement Fraser Cowie, Jayaneethe Naranasamy, and Stephen Forrester, Gyrodata, explore how gyro while drilling technology can improve wellbore collision risk mitigation and well placement in challenging projects.


he role of wellbore placement in oil and gas operations has evolved in step with the industry itself over the last decade. Given the current economic challenges of operating in a pandemic and facing stagnant commodity prices, the focus has shifted to drilling wells that are more accurately placed and can quickly be completed and produced to begin the road to profitability. Fortunately, technology innovations through the years have brought the industry far in this domain, with one such advancement being in the area of gyro while drilling

(GWD) systems. There is an undeniable and direct link between high-accuracy wellbore surveying and better wellbore placement, and GWD technology provides a host of benefits not typically available with measurement while drilling (MWD) tools. With wells getting more complex, despite seeing decreased authority for expenditure (AFE) levels, a surveying system that can collect data of superior accuracy and precision in real-time while drilling has cleared the way for operators to achieve a level of performance not previously possible.

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Technology GWD technology collects real-time survey data to allow for more accurate wellbore placement and improved operational safety, with Gyrodata’s GWD systems enabling the collection of real-time data at all inclinations and any direction. The system provides continuous inclination and toolface from vertical while sliding and directional surveys on demand. In scenarios where magnetic

interference would compromise the data from MWD tools, a GWD system can typically provide improved survey accuracy and more flexible and cost-effective bottomhole assembly (BHA) design. GWD70TM and GWD90TM are Gyrodata systems that operate at maximum inclination angles of 70˚ and 90˚, respectively. The system is chosen based on the operator’s highest planned survey inclination, complete drilling plan, well type, and compatibility with other BHA technologies. When running a GWD system, an operator no longer has to use wireline gyros to orient or steer the drilling assemblies, and the precise wellbore guidance made possible by the system helps mitigate the risk of wellbore collision and ensure the well trajectory is correct. Understanding real-time wellbore position can make a large difference in a project’s operational and financial success.

Case study 1

Figure 1. Unmanned GWD operations are made possible by survey specialists onshore supporting rig personnel offshore.

Figure 2. The GWD surveys showed improved directional survey accuracy vs the MWD data while exiting the parent well.

Figure 3. Comparable ellipses of uncertainty from both systems validated the original MWD data and verified that the well was accurately placed.

18 | Oilfield Technology November/December 2020

An operator in the North Sea needed to conduct GWD operations on two offshore rigs to reduce the risk of wellbore collision, ensure precise directional control, and avoid adjacent wells in the congested field. Due to ongoing travel restrictions and personnel mobilisation challenges associated with the COVID-19 pandemic, it was not possible to deploy additional resources to the rigs or to the remote operating centre in Stavanger, Norway. As such, the operator needed to carry out the entire operation remotely, with GWD survey specialists interfacing with onshore and offshore colleagues from their home offices (Figure 1). GWD survey specialists used a third-party service company’s data visualisation and analysis platform, coupled with remote presentation from the remote operations centre in Stavanger, to continuously monitor all aspects of the operation. One component that was especially critical was the correct programming of the GWD toolface offset, as this would affect the entire operation if not done properly. On the first rig, the onsite MWD engineer shared their screen with the company’s remote survey specialist, who oversaw all programming as though they were physically present on the rig. On the second rig, the MWD engineer gave control of their screen to the Gyrodata specialist to allow them to successfully programme the tool remotely. This streamlined the process and reduced the overall time necessary for this part of the operation. The GWD70 system was then deployed to assist with drilling the wells, guiding the motor BHA from the kickoff point until the switchover angle was achieved for MWD gravity toolface and until the MWD data was clear from interference. Using the unmanned GWD solution reduced the interval of GWD surveys and enabled proper directional control to be achieved, with both wells successfully kicked off in the intended direction and wellbore trajectory ensured. Through diligent risk analysis and effective mitigation, all remote operations were executed without incurring any lost time. The operator eliminated the expense of mobilising personnel offshore by using the remote solution, which had the added benefit of reducing onboard personnel and thus reducing the risk of COVID-19 transmission. Communication between Gyrodata, the third-party service company, and

the operator resulted in all survey procedures being followed correctly, eliminating any extra rig time that would have been associated with retaking surveys due to error.

Case study 2 In another project, an operator in the North Sea was drilling a sidetrack from an existing well with a whipstock set at close to 90˚. The 6300 m horizontal section, which the operator was drilling with a rotary steerable system (RSS), had an initial zone of approximately 365 m where magnetic interference was expected to be an issue. Without valid survey data in this zone, achieving accurate wellbore positioning in the reservoir would have been challenging due to the length of the section. Cognisant of these concerns, the operator opted to use the GWD90 system to obtain higher quality surveys that would be unaffected by the magnetic interference from the motherbore and offset wells. The GWD90 system provided the operator with all-attitude, high-accuracy surveys in real-time as drilling progressed through the zone of magnetic interference. The system also offered collision risk mitigation when the BHA had a potential close call with any offset wells. The third-party service company had an ‘automatic pumps off’ function that allowed surveys to be collected during connections, which reduced the amount of necessary rig time for the operation. All GWD operations were carried out entirely remotely, with no delays or problems when confirming survey quality. Using the unmanned solution eliminated onsite personnel and mobilisation costs, saving tens of thousands of dollars. The GWD90 system provided improved survey accuracy vs the initial MWD surveys while establishing clear separation from the parent well (Figure 2), thus achieving the operator’s objectives. If the section had been surveyed by doing a pump-down wireline survey during drilling instead of using the system, it would have taken a minimum of 12 additional hours of rig time. This would have resulted in at least US$240 000 of charges based on an assumed daily rig rate cost of US$483 000, not including operating costs. Finally, using the system removed the risk of stuck pipe while completing the surveying operations, further validating the economics of running GWD in this scenario.

Case study 3 An operator working offshore Malaysia was conducting a drilling campaign using managed pressure drilling (MPD) to deal with a highly unstable formation. Because this drilling technique required the pumps to be turned on and off in stages before taking a survey or breaking a drillpipe connection, the operator faced the challenge of the survey tools’ sequences being interrupted. The operator requested a GWD system that would allow them to address wellbore collision risks and take high-accuracy surveys in a manner that would not affect the MPD pumping sequence. The GWD70 system provided data for advanced collision avoidance and real-time knowledge of wellbore position, enhancing performance and safety. Any flow within the pipe would have invalidated the data, as the GWD system required zero flow or complete BHA-string stationary time to record a survey. In this application, the customisability of the system was also a critical differentiator. By working with the operator to develop and implement the exact tool settings necessary to accommodate the irregular MPD pumping sequences, the

company was able to ensure that the surveying and MPD aspects of the operation would not interfere with one another. Before beginning the project and deploying the GWD system, the company conducted a comprehensive review with the operator to address project-specific MPD challenges so that they would not become an issue. In this case, two of the GWD70 system’s functions – survey delays and tool shutdown time – were customised to adapt to the MPD operations. Gyrodata successfully ran 24 surveys from 1855 – 2522 m at a maximum inclination of 66˚. As predicted, the surveys were taken without issue and without any interference between the MPD and survey sequences. Using GWD also eliminated the risk of stuck pipe and the need to run a standard wireline gyro, saving the operator on mobilisation costs, wireline unit service, and rig time for running the wireline. These savings were estimated to be at least US$75 000.

Case study 4 In another project, an operator in the North Sea needed to drill and geosteer a reservoir producing well from a platform using a jackup rig. The reservoir consisted of fine-grained chalk approximately 2400 m below the seabed. The operator indicated accurate wellbore placement and collision avoidance were their main objectives on this job, as there were several other wells in close proximity. Gyrodata recommended running the GWD90 system, which was customised to integrate with the service company’s MWD tool and BHA configuration. The compact GWD system was able to be run in a shorter, smaller-outer diameter (OD) collar than typically used, and the assembly was placed as close to the bit as possible to assist in collision avoidance if interference from nearby wells was observed. A standard collar length GWD assembly would have pushed the logging while drilling (LWD) tools further back in the drilling assembly, resulting in a negative impact on reservoir placement. The compact GWD system design also made tool preparation much easier and faster due to its shortened length. The system provided real-time gross error checks of the MWD tool while drilling the section. Magnetic interference was expected between 6050 and 6300 m, but there was less interference than originally predicted. Despite this, the system still provided accurate surveys throughout the 6 ½ in. wellbore to total depth (TD), which were used for comparison to validate the accuracy of the MWD data. Comparable ellipses of uncertainty were encountered in both sets of data, achieving the operator’s objective of wellbore accuracy (Figure 3). If magnetic interference had been as severe as predicted, however, the GWD90 system would have still performed to its error model’s accuracy; additionally, the system would have saved rig time compared with taking directional surveys with conventional wireline tools.

Conclusion Wellbore placement is one of the defining metrics of a drilling project’s success. If placed accurately, a well can better hit hydrocarbon-producing zones in the reservoir, while drilling with an optimised trajectory makes completion activities simpler and less fraught with error. In a world where commodity prices are not set to dramatically increase anytime soon, operators are learning to do more with less. Using a GWD system is a proven method of achieving wellbore placement and directional objectives that will increase the profitability and total return of a project.

November/December 2020 Oilfield Technology | 19

THE FINE MARGINS OF SUCCESS Cory Langford, Scientific Drilling International, USA, discusses how at-bit gamma ray images and continuous inclination measurements enable pro-active geosteering in tight target windows.


here are a wide variety of downhole logging tools which are used to effectively steer horizontal wellbores within a desired target window. The selection of the required real-time downhole measurements to be used in the geosteering process is largely based on the target formation’s expected log response across the drilling window. As the development process of an oilfield progresses, new methods for extracting the hydrocarbons are implemented. One of these methods involves extremely precise borehole positioning within the lateral’s target zone to maximise hydrocarbon recovery. Traditionally, operators who wanted to achieve the goal of staying within a geosteering window of <10 ft would utilise a rotary steerable

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system (RSS) for a decreased bit-to-sensor distance and better inclination control. With commodity prices for oil remaining in the US$30 – US$40/bbl range, the development of certain mature oilfields might not be economically feasible when the extra cost of running a RSS is required for geosteering purposes.

Azimuthal LWD data requirements While most horizontal wells can be geosteered with a traditional bulk gamma ray logging while drilling (LWD) sensor, there are instances where the target formation does not provide enough gamma ray contrast to adequately determine where the well is positioned by correlation to offset well logs. Azimuthal functionality of downhole LWD sensors provides an accuracy to well placement decisions made in real-time. Determining if an azimuthal gamma ray sensor or azimuthal resistivity tool is needed to stay ‘in-zone’ is usually decided before the well is drilled by looking at offset well data in a pre-well analysis. With a thin geosteering window, target changes in inclination become a critical component to keeping the well within the desired target zone.

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Bit-to-sensor offset effects on geosteering methods A decreased distance between the bit and LWD sensor can allow for a near proactive geosteering approach. Typical bit-to-sensor distances for gamma ray sensors connected to the measuring while drilling (MWD) probe above a mudmotor fall in the 30 – 45 ft range. This will depend on the length of the bit and motor, as well as the tool design offered by the directional service provider. RSSs will have a decreased bit-to-sensor distance of 10 – 20 ft, along with the option of a continuous inclination measurement of less than 10 ft from the bit. The shorter bit-to-sensor distance allows for quicker decisions on target changes to limit the amount of the well drilled out-of-zone by reacting quicker to structural dip changes along a lateral section. Proactive geosteering methods have normally involved running downhole LWD sensors with a deep depth-of-investigation (DOI) for a ‘look-ahead’ approach of adjacent bed boundaries. Since gamma ray sensors provide a relatively shallow DOI with long bit-to-sensor distances, they are generally used for reactive

geosteering programmes. Reactive geosteering can sometimes involve making target changes after the bit has already exited the target zone, resulting in over-correcting and porpoising the well to try and re-enter the ‘sweet spot’. With the advent of a geosteering sensor sub which is placed between the mudmotor and drill bit, bit-to-sensor distances can be decreased to less than 2 ft and provide a proactive approach to geosteering. Since the sub is placed below the mudmotor, having a short collar with reliable measurements is the key to success. Scientific Drilling’s BitSub LWD tool is 29 in. long and has azimuthal gamma ray, inclination, and tri-axial vibration measurements 16 in. above the top of the bit (Figure 1). The sub is run in conjunction with a compatible MWD system above the mudmotor and communicates via electromagnetic short hop. This Wi-SciTM technology works in both water-based and oil-based mud systems.

Unconventional shale applications

In the past decade, there have been huge improvements in the drilling and completions process of horizontal wells. These changes largely occurred after operators fully entered the development phase of large unconventional resources discovered across multiple basins in North America. Decreasing drilling costs were mainly driven by the increased reliability Figure 1. BitSub schematic showing the length of the collar, as well as the bit-to-sensor distance of 16 in. of downhole mudmotors and MWD systems, novel drill bit designs, drilling mud system enhancements, drilling rig horsepower increases and automation implementation, as well as the ingenuity of an industry that realised the potential of large untapped oil and gas reserves in unconventional shale reservoirs. Along with the step-change of reducing drilling days per well, new completion methods were trialled which resulted in higher extraction rates of hydrocarbons. Staggered well designs, zipper fracs, shorter stage lengths and higher proppant amounts have all contributed to increased production. While drilling costs have decreased dramatically, the cost of completions Figure 2. Gamma ray image log from unconventional shale reservoir’s horizontal section. has remained relatively high due to the aforementioned changes in completion design. In order to ensure the reservoir is being adequately drained after hydraulic fracturing stimulation efforts, the placement of wellbores within target formations is critical. If a well is drilled 100% within a target window, reservoir appraisal studies can be accurately performed to determine estimated hydrocarbons-in-place for a field by examining the production history of wells. Unconventional shale reservoirs continue to be a large focus for many E&P operators wanting to extract Figure 3. Gamma ray image log from conventional sandstone lateral section. the large amounts of hydrocarbons

22 | Oilfield Technology November/December 2020

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maintaining high rates of penetration while prolonging the life of downhole drilling bottomhole assembly (BHA) components.

Case study: conventional reservoir

Figure 4. Gamma ray image log from coal-bed methane well.

Enhanced oil recovery (EOR) programmes for mature conventional sandstone reservoirs benefit from decreased bit-to-sensor distances due to the necessity of precise wellbore placement in the reservoir. There are instances where the BitSub LWD tool has been utilised to keep a horizontal wellbore at the top of the target formation, in order to extract the trapped hydrocarbons without the additional costs of a carbon dioxide flood. Other case studies for conventional reservoirs include drilling a lateral at the bottom of the target sandstone formation, in order to implement water-flood recovery efforts. Both scenarios have the geosteering programmes incorporate the at-bit azimuthal gamma ray and inclination from the BitSub LWD tool for maximised target zone exposure. Figure 3 shows an example of how the BitSub gamma ray images can provide clear and precise indication of stratigraphic markers, even when the gamma ray is only fluctuating 15 API.

Coal-bed methane horizontal wells

Figure 5. Artistic representation of azimuthal gamma ray acquisition and at-bit interpretation from the BitSub LWD tool. trapped in the low permeable source rocks. In order to maximise recovery factors, well spacings of laterals have been reduced. With smaller drilling windows, directional survey management and geosteering have become critical inputs into modelling offset fracture interference between adjacently producing parent wells. Multi-well pads and stacked plays have further increased the density of wells in a given area. Directional control and geosteering confidence play a considerable factor in minimising dogleg severity along a lateral section. Figure 2 illustrates how the azimuthal gamma ray identified that the well came out the top of the target zone, and the well trajectory was adjusted using the at-bit inclination measurement. Having at-bit inclination allowed for active monitoring of motor yields while sliding, preventing an over-correction of course adjustment. In addition, drilling dynamics measurements at the bit can be used for constructing optimised drilling parameter roadmaps for the purpose of

24 | Oilfield Technology November/December 2020

At-bit gamma ray and inclination measurements were primarily developed for coal-bed methane wells, where fractured coal seams, which are stratigraphically bound by shale caps above and below, are targeted with horizontal wellbores to maximise hydrocarbon production. Steering within these coal beds involves multiple target inclination changes, since their thickness can be as little as 5 ft. Having accurate real-time azimuthal gamma ray and inclination ensures that when the bit strikes the shale cap, a confident decision can be made to steer the well back down into the target zone. With a gamma ray sensor at the bit, out-of-zone lateral percentage is minimised due to the proactive geosteering method of identifying whether the bit is cutting up or down the structure. Figure 4 shows a gamma ray image log from the LWD tool showing the well succeeding to stay in-zone by recognising the at-bit inclination starting to build during rotation.

Drilling optimisation from at-bit measurements LWD tools have a long history of proving their value to geosteering and petrophysical interpretations. The real-time data they provide can influence important decisions about target well trajectories, ultimately affecting the post-well production and completion strategy (Figure 5). Their benefits to the drilling department have been relatively scarce, as they are usually located above the mudmotor and do not provide any insight into motor or bit performance. Through the use of technologies that provide downhole at-bit measurements, such as BitSub, real-time information is created that can steer the well in a tight geosteering target window with minimal gamma ray contrast, and additionally supply the inclination and tri-axial vibration measurements for drilling parameters and mechanical specific energy optimisation.

Andreas Hofmann and Willem van Strien, SGS, the Netherlands, discuss new technologies for reservoir characterisation and field and facility health monitoring.


he need for low-cost solutions and enhancing the sustainability of existing facilities and infrastructure in the oil and gas industry has promoted the development of numerous technologies for reservoir characterisation, production optimisation and the monitoring and preservation of well and facility integrity. In recent years, the development of laboratory analytical techniques has also resulted in an order-of-magnitude increase in resolution and precision. The commercialisation of techniques, which previously were only designed for academic applications, has triggered significant innovation in the oilfield services sector. High-tech analytical methods now allow for more reliable petrographical, petrophysical, geo-chemical and rock-mechanical analyses of rock fragment sizes smaller than even 0.1 mm. These developments in turn triggered a significant growth in the use of cuttings, a byproduct of the drilling process rarely used in the past. Apart from solid cores, drill cuttings are often the only tangible rock samples coming

from the subsurface. The routine application of these novel technologies to cutting material is set to lead to a reduction in core acquisition and subsequently have a substantial impact on the cost of drilling. In combination with wireline and measuring while drilling (MWD) logs, the data acquired from cuttings can be used for reservoir characterisation, geomechanical models and the detection of reservoir heterogeneities. It is not only geologists and petrophysicists who benefit from detailed mineralogical assessments of solids (e.g. rocks). High-resolution chemical and mineralogical analysis technologies also help production engineers and production chemists to analyse the chemical and mineralogical composition of scales, produced particles (e.g. sand) and the products of corrosion. The monitoring of contamination levels and the changes in the chemistry of the solids and fluids helps to detect potential plugging risks and erosion/corrosion processes at an early stage and to optimise mitigation programmes. Both corrosion and scaling are threats to the safe and economic operation of oil and gas assets.

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The development of low-cost and fast turn-around microbial DNA analysis technologies in the last decade, such as next generation sequencing (NGS), ushered in a new era for the oil and gas industry.

By applying NGS technology on cuttings and reservoir fluids, it has been realised that oil and gas reservoirs and production facilities have diverse microbial ecosystems. The determination of microbial population diversity and metabolic pathways gives insight into reservoir health and the integrity of operation facilities. The application of microbial DNA technology to the oilfield is still not as common as in other industries (such as food and pharmaceuticals), but it already serves various functions, such as: Detection and diagnosis of microbial driven impacts e.g. microbial influenced corrosion (MIC), reservoir souring and biofouling. Monitoring of the efficacy of biocide chemistry and dosage. Development of microbial production logging tools to identify key producing zones. Monitoring and mitigation of field souring. Development of synthetic DNA tracers. Microbial enhanced oil recovery (mEOR). ‘Micro-seep’ detection for exploration purposes.


Figure 1. QEMSCAN image of pit caused by microbial attack. Pit depth is approximately 3 mm. Red and green indicate different iron-(hydr)oxide minerals with varying levels of chloride. Dark blue is siderite and yellow is iron sulfide.

Microbial DNA analyses, sampled from different reservoir types and fields, have shown that each hydrocarbon accumulation has a unique and characteristic microbial fingerprint. The microbial population is controlled by variables in the downhole reservoir environment, e.g. the temperature, salinity, pH, nutrients and lithologies. Differences in microbial patterns between stacked reservoirs within one field have even been observed, which suggests that, in the future, reservoir zonation in a field could be based on microbial ‘stratigraphy’.

Case study: failure analysis and corrosion forensics

Figure 2. Cross-section showing MIC. This pit developed below a


Figure 3. Krona plot showing the microbial assemblage at the corrosion site acquired through NGS indicating MIC risk.

26 | Oilfield Technology November/December 2020

Several water injection wells in an oilfield in the North Sea experienced a deterioration in injection performance and unexpected increased annulus pressure. Classical petroleum engineering methods and logging (such as full-bore electromagnetic wall thickness measurements) were conducted but the cause of the failure remained unidentified. The corroded tubing was pulled and thoroughly analysed, in order to determine the root cause of the failure. 3D laser scanning of the retrieved tubing sections was applied to analyse the metal loss of the individual wells, which showed extensive localised corrosion. Techniques were applied on the corrosion products sampled in the tubing, which included analysis of the mineralogical and chemical composition of the corrosion products using quantitative evaluation of minerals through QEMSCAN technologies. The mineral composition of the corrosion products located near a corrosion site are the result of chemical reactions between constituents of the injection water, released metals and (in this case) metabolic products from microbial biofilm surface interactions. Through studying the mineralogy and the texture of the corrosion products the genesis and growth history of the corrosion pits could be reconstructed. Furthermore, microbial samples were taken directly from the corrosion sites during retrieval. Molecular microbial techniques, such as quantitative polymerase chain reaction (qPCR) and NGS, were deployed to identify the entire microbial population responsible for the corrosion process. The integration of these detailed analyses allowed the reconstruction of the microbial and electro-chemical processes that took place inside the tubing down to micron scale. It was concluded that MIC, aided by high chloride levels and triggered by the presence of biogenic hydrogen sulfide (H2S), led to aggressive corrosion



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and subsequent failure of the injection tubing. Released corrosion products floated into the reservoir and caused the deterioration of porosity and permeability, which significantly reduced the performance of the injectors. Based on the results from the ‘corrosion forensics’, the mitigation strategy was revised and optimised with the objective of minimising future corrosion of the injection strings. Furthermore, an analysis programme of the corrosion products was established for the monitoring of the efficiency of corrosion mitigation and to detect severe corrosion at an early stage of the process.

Case study: mechanical properties from rock fragments

Figure 4. Nano-indenter (top); indentation impact on sample (bottom).

Unconventional shale plays are very prolific gas reservoirs in North America. The identification of reservoir ‘sweet spots’ and zones for efficient hydraulic stimulation is challenging primarily due to their mineralogical and mechanical heterogeneities. SGS has developed technologies and workflows that use fragmented core material or drill cuttings, together with wireline logs, to map reservoir heterogeneities and identify the ‘sweet spots’ and reservoir sections with rock-mechanical properties favourable for hydraulic stimulation. Rock fragments (crushed core and cuttings) from 20 sampling stations of the reservoir section of a shale formation were analysed. The mineralogical composition and rock-mechanical properties of the rock fragments were analysed using QEMSCAN and nanoindentation technologies. Based on the analysis of the mineralogical composition, representative litho-types for each of the 20 sampling stations were defined and the elastic mechanical properties of the various litho-types were determined by using nanoindentation. High resolution digital rock models were constructed for each observed rock type by incorporating mineralogical composition, texture, porosity, pore fluid density and the elastic mechanical properties measured from the nanoindentation. Geomechanical finite element modelling (FEM) was used to calculate the bulk mechanical properties under reservoir pressure conditions for each identified reservoir zone. The bulk rock-mechanical properties derived from FEM were calibrated at conventional triaxial core tests, which were only available from small sections of the reservoir. The bulk elastic mechanical rock properties modelled for the cuttings – together with Young’s Moduli and Poisson’s Ratios calculated from dipole sonic logs – were used to fill the ‘gaps’ between the sparse triaxial core tests. From the extrapolation and up-scaling of the calibrated bulk rock-mechanical properties a geomechanical profile was established for the entire shale reservoir section that captured the lithological and mechanical heterogeneities. The resulting geomechanical profile highlighted reservoir sections with rock-mechanical properties conducive to hydraulic stimulation (‘hard rocks’), and identified sections with less favourable rock-mechanical behaviour.


Figure 5. Cutting grain samples with indentation stations (top); Young’s Modulus calculated for each indentation station (bottom).

28 | Oilfield Technology November/December 2020

The automated rock properties by indentation (ARPIN) workflow applied in the study clearly highlights the effectiveness of the approach of utilising drill cuttings to derive geomechanical properties. Geomechanical data from the well is generally scarce; therefore the workflow adds value in acquiring geomechanical information in any section of interest. Since it is done based on the available drill cuttings, the approach is also cost-effective. The workflow could also be applied for hydraulic fracturing, seal and caprock integrity, or reservoir assessments where cores and logs are not available.

Larry Chen, Dr Nihal Obeyesekere, Thusitha Wickramarachchi, and Dr Jonathan Wylde, Clariant Oil Services, USA, analyse high temperature stable corrosion inhibitor development for deepwater applications.



ith increasing world energy demands, the petroleum industry has explored and produced in much more hostile subsea and deepwater environments. This has resulted in many high pressure, high temperature (HPHT) oil and gas wells around the globe. Consequently, the demand for high temperature stable and umbilical deliverable corrosion inhibitors has also increased. The demand is even higher for high temperature effective and environmentally acceptable corrosion inhibitors.1,2,3 It is very challenging to develop chemicals that are both thermally stable and effective for the HPHT conditions often prevalent in deepwater applications. As part of a study, several water-soluble and oil-soluble products have been developed that are thermally stable above 200˚C (390˚F) and maintain high corrosion inhibition efficacy. One product was found to be stable at 200˚C for 2 months under inert HPHT conditions.4,5,6

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Chemical design and qualification More than 100 chlorine (CI) formulations were designed and tested during this study. The active chemicals were blended with high flash point solvents to yield 35 – 40% activity for equal comparison convenience. Any formulated products that were unstable (e.g. phase separated) were rejected. The remaining products were screened and evaluated to qualify for subsea high temperature applications by following the principles laid out in API 17 TR5 and API 17 TR6 for qualifying subsea production chemicals. RCE tests (Rotating Cylinder Electrode, ASTM G185) were used to initially screen all experimental blends at shear stress of 7 Pa – this technique is limited to low temperature (<90˚C) and low pressure (1 bar). To test under HPHT conditions, RCA testing (Rotating Cage Autoclave, ASTM G184) ensured the products

performed up to shear conditions of 40 Pa.7 Finally, higher shear testing was performed on a jet impingement device (ASTM G208, shown in Figure 1). Synthetic brine was used for all performance tests and real field oil was used as required by the tests. As well as inhibition efficacy testing, the ‘secondary performance properties’ are equally important. These include: inhibitor partitioning, emulsion and foaming tendency, fluid compatibility, material compatibility, chemical thermal stability, chemical cleanliness (filtration specification), fluidity and pumpability, dynamic stability loop and EcoTox tests. It is important that experimental blends can perform over a wide range of temperatures and pressures, which explains the extent of the testing required, designed to mimic the extreme tortuous path that the chemical would have to endure as it travels through the cold, high pressure umbilical tube (4˚C and up to 12 000 psi) and as it travels downhole, enduring extreme highs of temperature and pressure (>200˚C and up to 12 000 psi).

Results and discussion Chemical thermal stability testing

Figure 1. Jet impingement system for high shear testing.

Four shortlisted products (A, B, C and D – already screened in thermal stability tests at 4˚C and 121˚C) were subjected to 200˚C for 48 hours and observed for signs of instability. The four products showed no signs of degradation after thermal exposure, as best indicated by Fourier transform infrared (FTIR) analysis. Figure 2 details Product B before and after ageing at 200˚C, demonstrating the product had the highest FTIR spectroscopy match-up of 95.87% between the heated and unheated samples. SAE filtration was also performed on the before and after thermal exposure as a secondary gauge of stability and no additional particulates were created in the chemicals after exposure.

RCE screening test

Figure 2. FTIR comparison graph between a fresh Product B and the thermal aged Product B at 200˚C for 48 hours.

Products A, B, C and D were evaluated by RCE using 50 ppm of chemical to distinguish the corrosion inhibition properties. The results showed that unheated Product B provided the quickest corrosion rate drop from the baseline in the first 2 hours after CI addition and achieved an overall 97.4% inhibition. In comparison, heated Product B provided 96.6% corrosion inhibition. A corrosion rate vs time graph is shown in Figure 3.

RCA and jet impingement testing

Figure 3. RCE test results – dosed 50 ppm chemical.

30 | Oilfield Technology November/December 2020

The RCE screening identified Product B as the best performing CI and this was taken forward to HPHT RCA testing. Test conditions were 200˚C, 1600 psi (0.21% carbon dioxide [CO2] + 0.00036% hydrogen sulfide [H2S] balanced with nitrogen [N2]), shear stress of 40 Pa, a CI dosage of 400 ppm all ran for 7 days using X65 steel coupons. Both heated and unheated Product B were tested in parallel and both products achieved a corrosion rate <3 mpy (>95% efficiency when compared to a blank). All test results are shown in Table 1, with examples of coupon pitting analysis in Figure 4. Product B was tested in the jet impingement at a shear stress of 1500 Pa. There was an average baseline corrosion rate of 2539 mpy and a corrosion rate of 127 mpy at the end of the test at a dose rate of 600 ppm with a protection rate of 95%. This test demonstrated the high tenacity of the corrosion inhibitor film once allowed to adsorb onto the electrode surface in the jet.

Secondary performance testing

Table 1. Autoclave test results – 400 ppm of chemical

Foaming tendency was evaluated Weight (g) Coupon Product with the high salinity brine. The number Initial results showed that Product B 81 21.4797 did not create a persistent and Product B 82 21.3242 stable foam, even when tested up (unheated) to 4000 ppm. At application dose 83 21.0990 rates (400 ppm) the foam height 94 21.3283 generated in the sparge test was Product B 95 21.1953 (heated) insignificant and collapsed in 96 21.3109 approximately 10 seconds. 30 21.1396 Similarly, emulsion tendency testing showed that at 400 ppm, Blank 31 20.6040 Product B addition yielded a 32 20.7076 clean water phase after just 5 minutes after agitation with a clean interface and homogeneous oil phase. Even at 10 times the recommended dose (i.e. 4000 ppm) the water phase showed only some yellowness/haziness after 30 minutes. High pressure viscometry of aged and non-aged Product B was performed at 4ËšC and up to 12 000 psi. Both products tested had a maximum viscosity of 40 cP (in accordance with the guidance for umbilical delivery (<50 cP at 12 000 psi) in deepwater applications). One of the harsher stability tests performed was the ‘subsea flow loop test’, which consists of 4 x 500 cm, Âź in. internal dia. (ID) SS316L coils contained within a chiller bath. HPLC pumps are utilised to circulate the chemical through the loops and a series of strategically placed pressure transducers employed for recording the differential pressure (DP) across the inlet and outlet of the coils and inline-filters. The principle of the test is to simulate the tortuous path a chemical undergoes during umbilical injection.


Weight loss (g)

Corosion rate (mpy)




























Average CR (mpy)

% protection







Heated Product B was tested and, after circulation for 7 days, the in-line filters were removed from the loop and visually examined, and no deposition was confirmed. Fluid compatibility was tested in case of contact with completion brine. No precipitates and solids were observed when Product B was exposed to fully saturated calcium chloride (CaCl2) and calcium bromide (CaBr2) bines at 400 ppm and 4000 ppm. EcoTox testing was performed on Product B to determine any impact on typical marine organisms. Results showed the components within Product B to be highly biodegradable (per OECD 306 testing) and do not have a propensity to bioaccumulate (Log Pow <3 per OECD 116). Toxicity testing showed minimal effect to Menidia Beryllina Larvival but an impact was noted against Mysidopasis Bahia, showing Product B has a degree of toxicity.

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necessary to manage the risk of application, where Product B showed excellent thermal stability at static and dynamic conditions under high temperature (>200˚C) and high pressure conditions. This water-soluble product was stable to 200˚C for more than 2 months. Product B showed outstanding corrosion inhibition within varied flow regimes under low and high shear stress in autoclave and jet impingement tests, passing all other secondary performance testing. The field application of this product in the Gulf of Mexico will be reported in the near future. Figure 4. Untreated blank coupon showing large pit (>50 µm depth) (left); coupon treated with 400 ppm heated Product B, no pits (only polishing lines) (right).



As offshore deepwater oil production continues to expand, producers and service companies alike are challenged with harsher conditions of temperature, shear, salinity and pressure. Chemical injection via umbilical plays a vital role in deepwater and ultra-deepwater chemical applications. The chemical cleanliness is extremely important in these harsher environments for umbilical applications. Exceptional measures must be taken to ensure that the corrosion inhibitor performance is not compromised due to these harsher conditions. Product B is an example of a carefully formulated, customised CI and was selected among many experimental blends for deepwater applications. Extensive performance testing is deemed

3. 4.




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1. OBEYESEKERE, N., NARAGHI, A., CHEN, L., ZHOU, S., and WANG, S., ‘Novel Corrosion Inhibitors for High Temperature Applications,’ CORROSION 2005, Paper No. 05636 (2005). SMITH, J. R. L., SMART, A. U., and TWIGG, M. V., ‘The Reaction of Amine. Polyamine and Amino Alcohol Corrosion Inhibitors in Water at High Temperature,’ Journal of the Chemical Society, Perkin Transactions 2, (1992), pp. 939 – 947. QURAISHI, M. A., ‘Tailoring and Synthesis of Corrosion Inhibitors,’ CORROSION 2004, Paper No. 04400 (2004). ESAKLUL, K. A., and BALLARD, A. L., ‘Challenges in the Design of Corrosion and Erosion Monitoring for Deepwater Subsea Equipment – Stretching the Limits of Technology,’ CORROSION 2007, Paper No. 07338 (2007). OBEYESEKERE, N., NARAGHI, A., CHEN, L., ZHOU, S., and ABAYARATHNA, D., ‘Synthesis and Evaluation of Biopolymers as Low Toxicity Corrosion Inhibitors for North Sea Oil Fields,’ CORROSION 2001, Paper No. 01049 (2004). OBEYESEKERE, N., NARAGHI, A., PRASAD, R., and MONTGOMERIE, H., ‘Environmentally Friendly Corrosion Inhibitors for CO2 Corrosion,’ CORROSION 2000, Paper No. 00020 (2000). SKOGSBERG, L. A., and MIGLIN, B. P., ‘Establishment of Corrosion Inhibitor Performance in Deepwater Conditions,’ CORROSION 2001, Paper No. 01005 (2001).

Jean-Francois Ribet, 3X Engineering, Monaco, recounts the repair of subsea caissons at a North Sea platform, using composite wrapping.

ffshore platforms and their associated subsea pipeline networks have to function in harsh environments. On ageing North Sea platforms, corrosion, structural problems, leaks in seawater caissons and risers, dents, and mechanical damage to pipes and flowlines are all issues faced by operators. These can all hamper the functioning of the platform and production and, at worst, lead to the shutdown of a platform – an unacceptable outcome. However, it is not easy to solve these problems with traditional solutions, which usually require considerable logistics that can impede operations. A composite wrapping solution appears to be a new and efficient way to help platforms to repair these defects, removing the threat of a shutdown, while also being cost-efficient. In this context, ‘composite’ means fibre impregnated with resin that will cure and provide high mechanical and chemical properties to sustain and reinforce steel structures for a determined lifetime. 3X Engineering selected Kevlar fibre tape and an epoxy resin for its composite wrapping technology. Due to its high strain at failure properties, Kevlar enables a good composite sleeve deformation in line with pipe elongation. As the composite behaves in the same way as insulant material, there are no galvanic effects or cathodic protection issues. Moreover, its resistance to abrasion is good, and Kevlar fibre can be handled without any safety or health risks to the operator. The epoxy resin is made of a part A and a part B with different ratios, depending on the selected resin. In contrast to polyurethane resin, it is entirely solid and has no volatile components, which enables a simple and efficient implementation and guarantees the quality of the composite. No water is required during its application on the pipe – an important consideration, given that water is a key cause of corrosion – and it will not create carbon dioxide (CO2) bubbles during the resin reaction; CO2 bubbles can be trapped in composite sleeves and weaken the composite’s efficiency and lifetime.

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The composite has to be designed according to the two main standards, ISO24817 (ISO) and/or ASME PCC2 (ASME), when it is used for treating external/internal corrosion as well as holes or leaks. Depending on the type of defect, the repair’s design lifetime can

reach as high as 20 years. ISO and ASME can also be employed to repair dents and cracks, but in the case of the latter a finite element analysis (FEA) is preferable.

Case study 3X Engineering, alongside its partner in the North Sea, was asked to solve corrosion and leak problems on the subsea caissons of an offshore platform. The caissons were experiencing corrosion that had created holes with diameters of up to 300 mm. The challenge was to implement a solution that took into consideration the harsh environment (e.g. cold water of between 4˚C to 12˚C, depending on the season, and the specific salinity level of the sea), the specific steel grade, and the repair depth, which could range from -5 m to -20 m. Each composite repair was engineered to restore the serviceability of the caissons. Once the inspection was completed and the defects data received, the company undertook the required analysis and technical offers, using internal software that complied with ISO and ASME and carrying out a FEA. The proposed technical solution was to: Clean the caissons and sandblast them in order to achieve at least a SA2.5 surface preparation and a minimum roughness of 60 μm. Cover the hole with plate and a specific subsea filler developed by the company. Cover all of the sandblasted surface with a subsea primer. Prepare the composite tape on the platform using the company’s BOBiPREG®, an impregnation tool. Wrap the composite tape on the caisson using a hydraulic-driven wrapping machine monitored by the divers.


Figure 1. View of the subsea caissons.

Figure 2. Measurement of the defects.


To ensure the solution was suitable, a number of full-scale tests were performed in real-life conditions. After the first test, the main problem noted was the adhesion between the composite and the steel, because of a combination of low temperatures and the steel grade. The client required 5 MPa, as stated by the ISO standard. The first results were not positive. A primer was therefore required that could pass the required adhesion test. Once one was selected, a new full-scale test took place and the results met the client’s requirements. The adhesion test, performed by DNV GL Norway, returned results of 11 MPa on average (two times greater than the initial requirement). DNV GL gave its official approval to the client, meaning the onsite application could start. Regardless of the technological advancements in the sector, a subsea repair still remains a challenging intervention. Given the unpredictability of the North Sea, the safety of the divers was a key requirement. The divers were therefore trained to properly apply the composite wrapping. During the application, they were monitored by technicians on the platform through radio and a camera. Despite delays due to bad weather, the application of the composite wrapping was successful. Depending on the defect, the repair length varied between 780 mm to 2340 mm for a total composite wrapping length of 6800 mm. The wrappings were made both on a straight line and on tee.


Figure 3. Tape wrapping machine monitored by diver.

34 | Oilfield Technology November/December 2020

The company continues to develop its subsea composite wrapping in order to meet new client demands. One potential avenue is to explore diverless subsea composite wrapping and deep offshore pipe repairs. If necessary, the company can performs tests in hyperbaric chambers to replicate the conditions (e.g. pressure and temperature) of deepwater environments.

Gilberto Gallo, Drillmec, USA, outlines the importance of technology to rig design and improving drilling performance.


he current market has tightened the space for drilling rig innovation, and rig design is caught in between necessity and limited economic feasibility. Drilling rig advances are therefore shifting from structurally based to data-driven and process-based ones that seemingly represent a more affordable low hanging fruit. The evolution of the full drilling rig packages now involves a total integration of the different product lines under one system of data management that produces key data for both operations and maintenance. In order to effectively exploit this potential, machine learning and AI are gradually being introduced and utilised, opening up to all sorts of data mining to improve drilling performance, equipment durability and maintenance, and reliable and safe operations. However, there still is plenty of room for conventional, operation-based progress, especially by using the newly historical data benchmark exploring new patterns and trends. For example, a recent study on statistics per well in the Permian Basin in Texas, US, showed that 97% (of the 10 terabytes per day per single well) was not being analysed. One of the largest

operators contracted a leading service company to analyse 7 years of data on progressive cavity pumps (PCPs), and through machine learning created an application capable of predicting with nearly 90% accuracy the exact day on which the equipment would incur problems, considerably improving predictive maintenance. The combination of the different advances has dramatically reduced the time for vertical wells drilled and the rig count, where 1000 rigs are able today to cover more ground than 4000 in the 1980s, in the US alone. This achievement went through several cycles of mostly incremental technology improvements, and taking a look at the nature and history of these enables understanding of the importance of innovation in the field, even during a down cycle like the current one. The historical evolution described in this article emphasises the different types of innovation, both in equipment and automation, developed in the HH-Series hydraulic hoist rigs across a 25-year evolution, culminating in fully automatic operations with the latest accomplishment of automatic casing drilling.

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Figure 1. HH-300 mast on trailer.

Figure 2. A low emissions, soundproof HH-300 in town.

Figure 3. HH-300 automatic drilling rig enabling secure and efficient operations.

36 | Oilfield Technology November/December 2020

The HH-Series began in 1993 with a simple G-75 hydraulic rig for water wells in Italy, currently working in Ukraine. The fast mobilisation and the operations efficiency of this 75 t (165 000 lb) hookload water well rig laid the groundwork for further development of bigger models of series for oil and gas drilling and workover operations, with a focus on a compact layout and optimisation of rig-up and rig-down operations. The new design differed from conventional land drilling rigs since it did not present a conventional mast structure, or drawworks, long wires or travelling equipment. These were replaced by a powerful hydraulic cylinder, the main hoisting element of the rig, situated on a self-standing telescopic mast with reduced height, permanently mounted on trailers, with other features for faster moving operations (Figure 1). The hoisting system was extremely similar to the current one, based on a telescopic mast fabricated in compliance with API specifications, operating as a hydraulic hoist. It was designed to allow handling of API range 3 (45 ft) drill pipes, 30 ft drill collars, and API range 3 casings (45 ft). It was composed of two independent sections, with the bottom one fixed to the trailer frame while the telescopic section ran up and down. This new, patented design presented a tilting top drive installed on the telescopic mast, in combination with drill pipes stacked in vertical pipe bins. In the early 2000s, the development of additional hoisting capacity brought the adoption of 272 t hook load rigs (HH-300) in Argentina, Iceland and the US. The HH-300 used an automatic pipe handling system, which was capable of moving drill pipes from the vertical pipe racks to the mouse hole in complete autonomy. The old G rigs are now officially HH-Series. The pipe handler would rotate inside a unique vertical pipe rack surrounding the rig floor. The pipe handler’s arms, installed on a vertical rotating tower, had two clamps grabbing the drill pipes from any pipe of the pipe bins and moving them to the mouse hole or vice versa, depending on an electronic pre-set order. The top drive would then pick a pipe from the mouse hole, lift it and tilt it to the nearby pipe string in the centre hole. This disruptive innovation further reduced the rig’s footprint, given the vertical stacking of drill pipes instead of horizontally on the ground, and considerably improved the feeding of the pipes. The unmanned handling of drill pipe presented a crucial safety enhancement: in combination with a hydraulic iron roughneck, making up and breaking the pipe connections, no one was required on the drill floor, thus reducing the drilling crew and resulting in additional efficiencies and reduced liabilities. Key to this change was the cooperation and direct feedback of the drilling contractor combined with Drillmec’s ability in flexibly working on finding such a solution. The HH-Series from now on will have automatic pipe handling systems for models starting from the HH-150 and manual or semi-automatic systems for the smaller and more agile rigs. With 2006 came the first HH-Series, with a skidding system and self-rising trailerised pipe racks that started operating in Italy. In 2007, the HH rigs were used on an offshore platform in Congo for a French company, performing workover operations. Another noteworthy characteristic of the HH-Series rigs is its ability to run operations close and sometimes even in the middle of urban areas from small Swiss towns (Figure 2) to Dallas, Texas, US, while abiding by some of the most stringent noise and emissions parameters. The carousel structure of the vertical pipe bins helps contain most of the noise and supplementary levels of soundproofing are achieved by solutions affecting generator sets, HPU and mud pumps. An anti-spill feature on the rig floor and another floor under the pipe handling system make the HH-Series safe and respectful of the surroundings.

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Figure 4. HH automatic casing handling tool.

The first HH-150 was delivered in Siberia, Russia, in 2010, and was able to handle a temperature of -45˚C. The broadness of the portfolio was expanded with the HH-350, with 350 t of hoisting capacity deployed in Colombia and New Zealand in 2011. In the same year, an HH-102 started performing workover operations in Chile while another 25 HH-75 went to China. In 2012, the first slant HH-75SL started drilling for a major oil company in Australia: it utilised a horizontal pipe handling system at different slanted angles going from 5˚ to 45˚. The same slant concept was applied the following year to an offshore HH-220 in the UK and in Norway for workover operations.

In 2014, several HH-300 rigs with walking systems started drilling in Venezuela. At this point, the HH rigs are highly automated, safe and effective machines that can drill 80% of existing wells, efficiently performing oil and gas and geothermal drilling and workover operations in six continents. The advanced automation, combined with key software features, was another fundamental factor that helped the spread of more than 200 units across the globe. The automation of certain routine drilling operations such as tripping and the automatic pipe handling not only reduced the drilling crew, promoting safer and hands-off procedures, but also led to the latest and current version of the HH rigs and arguably the most important development: fully automatic operations. The first milestone in this regard was reached in 2015: fully automatic tripping operations with an HH-300 (Figure 3) through the new Drillmec Embedded Efficiency Platform (DEEP) and specifically the Drillmec Automatic Tripping System (DATS) software, once more improving safety and performance. The introduction of a more advanced cyber cabin, with more data points and the application of machine learning and AI, made this step possible. The last development is being deployed in 2020: automated casing handling. Once the casing is on the rack, it is automatically moved to the catwalk, which carries it through an opening in the middle of the pipe bins carousel directly to the centre hole, where the connection is also completely automatic and unmanned (Figure 4).

Conclusion The concept of a reliable, small footprint rig package, capable of operating completely automatically through standardised sequences at impressive speed in total safety, has come full circle.

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WHAT IS TO COME Stian Engebretsen, Aurore Plougoulen, and Lars Anders Ruden, Emerson Automation Solutions, describe an IIoT powered digital metering solution, which couples sensors, multiphase meters and virtual flow metering.


n the upstream oil and gas industry, multiphase metering is a central part of many applications and processes, such as reservoir management, field development, operational control, flow assurance and production allocation. In this context, the implementation of Industrial Internet of Things (IIoT) systems unlocks online production monitoring and allows field operators to monitor their wells and obtain real-time and continuous well information. Multiphase flow meters (MPFMs) and virtual flow metering (VFM) can be combined to provide operators with a reliable solution powered by IIoT to estimate the in-situ flow of oil, gas and water within wells and flow lines. This article addresses the combination of MPFM and VFM systems and illustrates the technology with two use cases: one where MPFMs are the main well allocation method, and the other where VFM is used as the main well allocation method.

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Technical introduction to the concept of MPFMs and VFM Multiphase flow metering is the task of estimating the fluid phase flows of (typically) oil, gas and water within pipes such as wells and flow lines. In the upstream oil and gas industry, multiphase metering is a central part of many applications and processes, such as production control, reservoir/production monitoring and optimisation, and production allocation. The main problem is measuring the contents flowing inside the pipes in near real-time without significantly affecting the process. The traditional way of measuring the production of a well is to route the fluids through a test separator for a given period and measure the single-phase flow at the outlets using accurate, fit-for-purpose meters.

However, frequent well testing reduces production regularity and introduces additional pressure loss, hence the need for a solution that lowers overall costs, minimises disruptions from periodic well testing, and enables accurate measurement of the contents flowing inside the pipes. During the 1990s, two similar but different methods of multiphase metering emerged onto the market, where sensor measurements were used to estimate the in-situ flow – MPFMs and VFM. Advances in both sensor technology and the computational power of computers were enablers of these technologies. Sensors measure intrinsic properties of the flowing media with high accuracy, such as pressure and temperature; measurements are then converted into flow rates using a metering system. A MPFM is installed directly in the flow trajectory and uses the combined measurements from multiple sensors to estimate the flow rates through the meter. Virtual metering relies more heavily on the mechanistic flow models, but similarly to MPFM, it uses sensor measurements as input to estimate the flow rates – the sensors can be located at different locations throughout the flow trajectory.

The digital transformation in multiphase flow metering Figure 1. Schematic of equipment and sensors for a well with a multiphase flow meter. The active components used by the VFM in this example are shown in black – pressure and temperature sensors, water fraction and venturi from MPFM and choke valve position.

Since the 1990s, much has happened on different technology fronts: while sensors, data acquisition and software have known great innovations, the IoT trend has created the IIoT.

Sensing Sensors for pressure and temperature have become more accurate and reliable. Downhole gauges for pressure and temperature are now a proven technology with better accuracy and reliability, and data attenuation. Downhole gauges are important for VFM, as they enable flow models to be matched against the response from downhole to wellhead.

Data acquisition Figure 2. Flow rate results from MPFM and VFM vs time using instrumentation as

shown in Figure 1. The relative errors between MPFM and VFM are in the range of 10 – 15% in the left half of the plot and 3 – 5% in the right half.

Different data acquisition systems, such as supervisory control and data acquisition (SCADA), distributed control systems (DCSs) and production historians, can aggregate hundreds of thousands of data points from oil and gas fields down to second interval sampling. Data acquisition systems are now able to push production data to cloud solutions, an enabling technology for digital transformation.


Figure 3. Emerson’s web application dashboard displays real-time inputs from the field and estimated flow rates vs time. The near real-time equipment inputs are shown in a list on the right.

40 | Oilfield Technology November/December 2020

Innovations in algorithms as well as hardware improvements have resulted in greater capacity for modelling big systems close to real-time. With available data from real-time data acquisition systems, online production monitoring is enabled and can be deployed in cloud-based solutions. A virtual metering system is a true IIoT application, in the sense that it is enabled by distributed sensor and equipment information which is gathered by an acquisition system and analysed using a dedicated software application. VFM is a combination of separate systems which return great benefits. There are two main approaches to VFM – model-based and data-driven utilising machine learning (ML). Since ML needs data to train models to be predictive, the models will obtain more data for training. Both approaches have pros and cons, as production continues. This article will focus on model-based VFM, which relies on mechanistic multiphase flow models that have predictive capabilities out of the box, but like ML, are vastly improved with available calibration data. For this method, a representative model of the production system must be built using the fluid properties

and the static model information (well and flow line trajectories, location of equipment and sensors, etc.). The model is then calibrated using available data such as well tests, MPFM, or metered data from separators.

VFM for assistance, backup and validation of the MPFM system MPFM is used both in subsea and onshore contexts and can be installed directly on wellheads or on flow lines. MPFM is typically installed on high producing wells where the investment is justified or where accurate production allocation is important, such as for custody transfer between operators. For fiscal metering, accuracy is naturally an important factor given the economic consequences, and that is where virtual flow metering in combination with MPFM adds further capabilities in data validation, to increase confidence in the flow rate allocation. VFM incorporates all relevant measurements in a gathering system; depending on the available instrumentation/sensors, it provides an independent system that can validate the results from installed MPFM and add backup. This is crucial when accuracy and robustness are of major importance. An example is considered where MPFM is installed on the wellhead of an oil producing well. The example illustrates the multiphase metering capabilities of VFM when downhole gauges, wellhead sensors, venturi and water fraction estimates from MPFM are available, in addition to reference data for model calibration. Figure 1 shows the active equipment used for the calculation (black) and the inactive components (pink). With the available instrumentation presented in Figure 1, results are shown in Figure 2 for the oil phase. The results show a good qualitative match between MPFM and VFM, though with larger relative errors seen in the period represented in the left half of the plot. For this setting, VFM is partially dependent on MPFM due to the water fraction estimates, but the downhole sensors enable VFM to match the model with the pressure loss in the well bore, resulting in a decent match with MPFM and VFM. Engineers and operators can diagnose sensors and equipment by comparing results from VFM and MPFM. Divergence and systematic drift may indicate problems with the instrumentation or be a sign of solids precipitating within the pipes. In the event of the flow being compromised, it is valuable to have a VFM system assisting the MPFM with diagnosis when expensive remedial actions are being considered. With MPFM available, there is also the possibility of using the flow rates as input to the VFM and comparing the sensor deviation output by the VFM. In such a setting, the VFM is mainly used as a validation system, but it may still give an additional view into the production system. Using a near real-time VFM system for production monitoring can be a powerful tool for gaining insight into the production system and reservoir. Physical properties from the VFM model can be extrapolated and shown at any position in the flow trajectory, such as downhole or downstream in the gathering network. Erosional velocity limits, hydrate formation temperatures, and liquid hold-up or other parameters of interest can be viewed at key locations in near real-time. User interfaces may provide direct insight to the online results, showing the match of different sensors and instrumentation. In the dashboard in Figure 3, an example is shown where the calculated and measured properties are displayed on the right. Operators and engineers may use this information to diagnose and fix operational problems more quickly, which in the long run leads to more efficient production.

VFM as the main well allocation system with assistance of MPFM VFM can be used to estimate flow rates in a production system given the right instrumentation. As a bare minimum, wellhead sensors measuring pressure and temperature are needed, but if these are the only sensors available, regularly performed well tests are required for fixing fluid ratios.



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Figure 4. The output from the network simulation shows the variations in GOR and WC for the five wells.

Figure 5. Network topology for the two VFM examples. Wells P01, P02, P03 and P07 are producing to a wellhead platform and P08 is a satellite well coming into the same platform.

In the following examples a simulator is used to model five wells producing to a common wellhead platform. The results from the simulator are then used as input for a second VFM calculation, applying only pressure and temperature sensors at the wellhead, choke and gas lift settings, and fixing gas-oil ratio (GOR) and water cut (WC) once a month to see the effect of regular well tests. The GOR and WC in the individual wells vary between well tests, and consequently, the accuracy of the well test-based calculation will be significantly affected. Figure 4 shows the simulated GOR and WC for the five wells. The GOR in well P08 is rapidly changing from 1200 down to below 200, and well P07 and P02 are increasing relatively quickly in WC. The resulting oil rate from the VFM is shown in Figure 5, labelled VFM_WH. A second example is now considered based on the same simulation, where the downhole gauges and real-time WC measurements per wellhead are used in addition to the wellhead sensors. Downhole gauges enable measurement of the pressure differential representing both gravitational and frictional loss, which is key to obtaining reliable results in VFM. WC measurements from a simple MPFM are required here to estimate the multiphase flow, as three phases (oil, water and gas) are produced from the reservoir. Using MPFM and downhole gauges allows measuring of the WC and to estimate the GOR with the VFM system. Thus, the well tests are no longer needed to fix the WC and GOR. The results are shown in Figure 6, labelled VFM_DH_WC. The same model foundation is used to both simulate the field responses and for VFM; thus, errors in fluid properties, sensor measurements, choke valves and gas lift rates are not introduced. These two VFM examples highlight the impact of available data on the accuracy of the oil rate metering. The average relative errors in the oil rate for the two different cases are shown in Table 1. The table shows that using monthly well tests to fix GOR and WC and utilising wellhead sensors for the VFM result in an averaged relative error of ±6 – 9% on wells P01, P02, P03 and P07, while using additional equipment such as downhole gauge and MPFM reduces it further to 2%. Well P08 has a rapid change in GOR (Figure 5), which poses challenges to both approaches, as indicated by the larger errors for this well.


Figure 6. Flow rates of oil estimated by VFM using two different instrumentation

configurations. The VFM_WH uses monthly well tests together with wellhead pressure and temperature. The VFM_DH_WC uses wellhead pressure and temperature, WC measurements and downhole gauges, but it does not rely on well tests. The green reference value shows the simulated ‘truth’ which the blue and red are trying to reproduce. Table 1. Average relative errors in % comparing the oil rate of VFM results with simulation results P01 (%)

P02 (%)

P03 (%)

P07 (%)

P08 (%)













42 | Oilfield Technology November/December 2020

Combining MPFM and VFM systems provides field operators with a flexible solution that can be adapted to their needs and constraints to measure the contents flowing inside the pipes in near real-time, without significantly affecting the production process. Assisting, backing up or validating the MPFM system with VFM not only increases operator confidence in the flow rate allocation, but also enables early identification of metering deviation. While using VFM as the main well allocation system can represent a more cost-effective solution, the choice of the main technology to use should reflect the profitability of the production system and the expected accuracy. Powered by IIoT systems, the featured multiphase flow metering technology is improving the speed and accuracy of decision-making and corrective actions. Bringing together IIoT devices and web applications provides engineers and operators with access to real-time inputs from the field and estimated flow rates vs time. This real-time flow of information enables them to diagnose and fix operational problems more quickly, leading to more efficient production. The digital transformation in multiphase flow metering is just one illustration of how leveraging the IIoT is helping oil and gas industries to gain a competitive advantage.

Brian Kettner, Badger Meter, USA, highlights the importance of selecting the right flow meter for oil and gas applications. low measurement is an important aspect of many operations in the upstream oil and gas industry. Users choosing equipment to meter the flow of liquid or gas processes must consider a wide range of factors to arrive at an optimal solution, including: Demands on operating companies. Common measurement methods. Making the right meter choice.


To succeed in a competitive global marketplace, oil and gas companies must meet rigorous demands for process efficiency, asset reliability and energy consumption. Upstream operations are also becoming larger and more complex, putting pressures on capital investment, onstream reliability and production quality.

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Modern oil and gas facilities are heavily reliant on flow processes. Accurate and reliable measurement technology is vital to their efficiency and safety. Typical flow-metering applications in the upstream sector include: Fiscal measurement. Field and well allocation. Process balances. Custody transfer. Chemical injection. Additive monitoring. Automated well testing. Pump-off control. Pump protection. Flare gas monitoring. Vent measurement. Tanker loading/unloading. Gas transmission. Leak detection. Waste treatment. Emissions monitoring.


When it comes to flow measurement, most oil and gas operators are focused on accuracy and cost. They must correctly match the flow meter and application to enable the best possible performance at the lowest overall cost.

no need for straight pipe lengths, as there are with other metering approaches. However, PD meters require clean fluids and can be large and burdensome to install.

Thermal mass Thermal mass flow meters have a relatively low purchase price. They are designed to work with clean gases of known heat capacity as well as some low-pressure gases not dense enough for Coriolis meters to measure. The main disadvantage of thermal technology is low- to-medium accuracy.

Turbine Turbine flow meters incorporate a time-tested measuring principle and are known for high accuracy, wide turndown and repeatable measurements. They produce a high-resolution pulse rate output signal proportional to fluid velocity and, hence, to volumetric flow rate. Turbine meters are limited to use with clean fluids only.

Impeller Impeller flow meters provide direct volumetric flow measurement, often with visual indication, universal mounting, fast response with good repeatability, and relatively low cost. Their performance suffers in applications with low fluid velocity. The meters are also sensitive to flow profile and can be used only in clean, low-viscosity media.

Variable area

Common measurement methods Flow meters are excellent tools to measure, monitor and control the distribution of a host of process fluids. The question is which technology to use, since a wide variety of meter designs are available. Each type of meter has pros and cons and must be properly deployed to achieve ideal performance.

Variable area flow meters are inferential measurement devices. Simple, inexpensive and reliable, they provide practical flow measurement solutions for many applications. Most variable area meters must be mounted perfectly vertically. They also need to be calibrated for viscous liquids and compressed gases. Furthermore, their turndown is limited and accuracy relatively low.



Coriolis flow meters directly measure fluid mass over a wide range of temperatures with a very high degree of accuracy. Their unobstructed, open flow design is suitable for viscous, non-conductive fluids that are difficult to measure with other technologies. With no internal moving parts, Coriolis meters require minimum attention once installed. However, they are sometimes considered too sophisticated, expensive or unwieldy for certain applications.

There are two types of ultrasonic flow meters: transit time and Doppler. Both designs will detect and measure bi-directional flow rates without invading the flow stream. Ultrasonic meters have no moving or wetted parts, experience no pressure loss, offer a large turndown ratio and provide maintenance-free operation – important advantages over conventional mechanical meters.

Vortex Differential pressure Differential pressure (DP) flow meters are versatile instruments that employ a proven, well-understood measuring technology that does not require moving parts in the flow stream. DP meters are not greatly affected by viscosity changes. However, they have a history of limited accuracy and turndown, as well as complex installation requirements.

Electromagnetic Electromagnetic flow meters will measure virtually any conductive fluid or slurry. They provide low-pressure drop, high accuracy, high turndown ratio, and excellent repeatability. The meters have no moving parts or flow obstructions and are relatively unaffected by viscosity, temperature and pressure when correctly specified. Nevertheless, their propensity to foul can cause maintenance issues. Electromagnetic meters tend to be heavy in larger sizes and may be prohibitively expensive for some purposes.

Vortex flow meters have no moving parts that are subject to wear so regular maintenance is not necessary. Only clean liquids can be measured with this type of instrument, as vortex meters may introduce a pressure drop due to obstructions in the flow path.

Oval gear The latest breed of oval gear meters directly measures actual volume. They feature a wide flow range, minimal pressure drop and extended viscosity range. This design offers easy installation and high accuracy, and measures high temperature, viscous and caustic liquids with simple calibration.

Nutating disc Nutating disc meters have a reputation for high accuracy and repeatability but are adversely affected by viscosities below their designated threshold, which affects performance. Nevertheless, meters made with aluminium or bronze discs can be used to meter hot liquids.

Positive displacement Positive displacement (PD) flow meters are highly accurate, especially at low flows, and have one of the largest turndown ratios. The devices are easy to maintain as they have only one or two moving parts. There is

44 | Oilfield Technology November/December 2020

Making the right meter choice In a typical upstream oil and gas facility, fluid characteristics, flow profile, flow range and accuracy requirements are all important considerations

in determining the right flow meter for a particular measurement task. Additional considerations, such as mechanical restrictions and output-connectivity options, can impact the user’s choice. For oil and gas users, the key factors in flow meter selection include:

Complications due to equipment accessibility, valves, regulators, and available straight pipe run lengths should also be identified.

Power availability

Fluids are conventionally classified as either liquids or gases. The most important difference between these two types of fluid lies in their relative compressibility. Consequently, any change that involves significant pressure variations is generally accompanied by much larger changes in mass density in the case of a gas than in the case of a liquid.

Today’s installations normally call for intrinsically safe instruments, which are ‘current limited’ by safety barriers to prevent a potential spark. Another option is to employ fibre optics. Turbine flow meters offer an advantage in environments where a power source is not available. They do not require external power to provide a local rate/total indicator display for a field application, and instead rely on a battery-powered indicator. Solar-powered systems can also be used in remote areas without power.

Measurement type

Industry approvals

Industrial flow measurements fall under one of two categories: mass and volumetric. Volumetric flow rate is the volume of fluid passing through a given volume per unit time. Mass flow rate is the movement of mass per time. It can be calculated from the density of the liquid (or gas), its velocity and the cross-sectional area of flow. Volumetric measuring devices, like variable area meters or turbine flow meters, are unable to distinguish temperature or pressure changes. Mass flow measurement requires additional sensors for these parameters and a flow computer to compensate for the variations in these process conditions.

Oil and gas firms are obliged to comply with strict standards set by the US Environmental Protection Agency (EPA), North American Industry Classification System (NAICS) and other regulatory bodies. The EPA, in particular, requires reporting of greenhouse gas (GHG) emissions to the atmosphere from flares and vents. Approvals for the use of flow measurement equipment in hazardous plant locations include FM Class 1 Division 1, Groups A, B, C and D; and FM Class 1, Zone 1 AEx d (ia) ia/IIC/T3-T6. Standards such as the Measuring Instruments Directive (MID) in the EU apply to fiscal and custody transfer metering for liquids and gases.

Flow rate data


A crucial aspect of flow meter selection is determining whether flow rate data should be continuous or totalised. A flow rate has to do with the quantity of a gas or liquid moving through a pipe or channel within a given or standard period of time. A typical continuous flow measurement system consists of a primary flow device, flow sensor, transmitter, flow recorder and totaliser.

Flow meter users must decide whether measurement data is needed locally or remotely. For remote indication, the transmission can be analogue, digital or shared. The choice of a digital communications protocol, such as HART®, FOUNDATION Fieldbus™ or Modbus, also factors into this decision.

Process media

Additional application criteria Accuracy demands Flow meter accuracy is specified in percentage of actual reading (AR), percentage of calibrated span (CS) or percentage of full-scale (FS) units. It is normally stated at minimum, normal and maximum flow rates. A clear understanding of these requirements is needed for a meter’s performance to be acceptable over its full range.

Service environment Flow meters can be employed under a host of varying conditions. For example, users must decide whether the low or high flow range is most important for their metering application. This information will help in sizing the correct instrument for the job. Pressure and temperature conditions are equally important process parameters. Users should also consider pressure drop (the decrease in pressure from one point in a pipe to another point downstream) in flow measurement devices, especially with highly viscous fluids. In addition, viscosity and density may fluctuate due to a physical or temperature change in the process fluid.

Fluid characteristics Users should make sure that the selected flow meter is compatible with the fluid and conditions they are working with. Some oil and gas operations involve abrasive or corrosive fluids, which move under pulsating, swirling or reverse-flow conditions. Thick and coarse materials can clog or damage internal meter components – hindering accuracy and resulting in frequent downtime and repair.

Installation requirements Planning a flow meter installation starts with knowing the line size, pipe direction, material of construction and flange-pressure rating.

Companies purchasing flow meters should remember that accurate instruments cost more according to their capabilities. It is better to locate the type of meter suited to a specific application before sacrificing features for cost savings. For the lowest uncertainty of measurement, PD meters are generally the best option. Electromagnetic meters provide for the widest flow range and turbine meters are usually the optimal choice for the highest short-term repeatability. Despite their high initial cost, Coriolis meters are ideal for measuring particularly viscous substances and anywhere that the measurement of mass rather than volume is required. Flow meter users should also take care to examine long-term ownership costs. A flow meter with a low purchase price may be very expensive to maintain. Alternatively, a meter with a high purchase price may require very little service. Lower purchase price does not always represent the best value. Generally speaking, flow meters with few or no moving parts require less attention than more complex instruments. The need to recalibrate a flow meter depends on how well the instrument fits a particular application. If the application is critical, meter accuracy should be checked at frequent intervals. Otherwise, recalibration may not be necessary for years.

Summary Selecting the right flow measurement solution can have a major impact on operational and business performance. For this reason, oil and gas companies anticipating a flow meter purchase should consult with a knowledgeable instrumentation supplier in the early stages of a project. The effort spent learning about basic flow measurement techniques, and available meter options, will ensure a successful application once the equipment is installed.

November/December 2020 Oilfield Technology | 45


Jรถrg Eitler, NETZSCH Pumpen & Systeme GmbH, Germany, highlights a case study in which an electric submersible progressing cavity pump system with a permanent magnet motor was able to convey efficiently and reliably. 46 |



or almost 70 years, a German oil and gas producer has been operating oilfields south of Bremen. For historical reasons, the company uses various types of pumps side by side. The installed centrifugal submersible pumps, pumpjacks, and progressing cavity pumps (PCPs) can handle local conditions, such as partially

deflected boreholes, paraffin mixtures, and sand mixtures with varying degrees of effectiveness. PCPs, as rotary positive displacement pumps, are particularly suitable for demanding media, such as viscous and abrasive media. However, the pumping rods, which are often up to 3000 m long, may break and the tubing can wear through.

| 47

Figure 1. In November 2018, a NETZSCH ESPCP system was installed in the oilfield of a German oil and gas producer. The picture shows the well, which was converted from a decommissioned pumpjack (right) to the rodless PCP (left).

By comparison, submersible centrifugal pumps do not use pump rods, but they are not very suitable for fluids that contain sand and/or gas. In an effort to reduce the number of pumping installations, the oilfield operator began to look for an efficient and durable system capable of combining the advantages of both types of pump: a system that combines a submersible motor of a submersible centrifugal pump with a PCP. However, the systems available on the market were out of the question, as they were equipped with a planetary gear system that is highly error-prone. The company finally decided in favour of a solution developed by NETZSCH Pumpen & Systeme GmbH that does not use that vulnerable component. It is a PCP system with underground drive and a permanent magnet motor (PMM). Even with the difficult media, it allowed higher flow rates than the previously used units. It also lowered operating costs due to its lower error rate. The company uses three different pump types for conveying operations on its crude oilfields south of Bremen. Due to their different design and functions, the different models work with varying degrees of effectiveness in the specific conditions of production wells. Each type of pump has specific advantages and disadvantages; for example, in the case of pumpjacks and PCPs, pump rod fractures occur relatively frequently. Since the rods move constantly during extraction, tubes may become damaged. This is more likely the further the borehole path deviates from the vertical position. As a result, time-consuming work may be required to repair the damage and resume production. In the case of submersible centrifugal pumps, this risk is much lower. They must be very precisely designed and carefully installed to avoid damaging the underground cable during installation, especially if the borehole path is not vertical. However, once the installation is successfully completed, the cables often have a much longer service life than the rods of PCPs and pumpjacks. This is because the cable is not under dynamic load during operation, as is the case with pump rods. The decision-makers considered a combination of PCP and submersible centrifugal pump, which combines the advantages of both pump types, to be particularly useful and efficient for the applications in the north German oilfields. Moreover, pumps of this kind have already been developed and assembled. These are the rodless PCP or electric submersible progressing cavity pumps (ESPCPs) – PCPs driven by a submersible motor. Based on the advice from oilfield specialists, the company decided on a special model developed by NETZSCH Pumpen & Systeme GmbH, which does not require a transmission ratio between the motor revolutions and the pump, since the motor selected specifically for this application can be operated at very low frequency. In addition to the PCP, the system consists of a PMM, sensors, motor protector, bearing unit, and a flexible rod called FlexShaft. Other components are a check valve, a drain valve, and a cable that is used to power the motor and to transfer data from the sensor.

Conveying of difficult media

Figure 2. In addition to the PCP, the system consists of a PMM, sensors, a motor protector, a bearing unit, and a FlexShaft. Other components are a check valve, a drain valve, and a cable that is used to power the motor and to transfer data.

48 | Oilfield Technology November/December 2020

The main parts which define the conveying principle of the PCP are a rotating component – the ‘rotor’ – and a fixed component – the ‘stator’, in which the rotor turns. The rotor is designed as a type of round threaded screw with a large pitch, large thread depth and small core diameter. The stator cavity has one extra thread and twice the pitch length of the rotor.

The precise geometrical mating means that conveying chambers are maintained between the stator and the rotor, which rotates inside it and also moves radially. These chambers continuously move from the intake to the outlet side and transport the medium. The volume of these chambers remains constant, and the chambers themselves are self-contained. This not only prevents backflow, but also ensures that the conveyed medium is transported at stable volume and pressure, so that no shear forces and hardly any pulsation occur. Other pumping systems soon reach their limits if consistencies vary, which results in interruptions, loss of pressure, and material damage. For PCPs, on the other hand, consistency and viscosity of the medium are not relevant to the flow. The multi-phase pumps from NETZSCH can therefore also handle mixtures of oil and water with sand or gas, reaching flow rates of up to 300 – 400 m3/d.

Improved handling The ESPCP used by the customer was also a model that has a special rotor connection, and was driven from below – from inside the borehole. The special feature of this pump is that the rotation of the rotor is not driven by the aboveground drive head via a very long shaft or rod; rather, the rotor-stator combination and the motor are sunk into the well. The motor and the bearing unit are connected directly to the rotor via a flexible rod. All radial and axial forces of the rotor are absorbed Figure 3. Since there is no pump rod, the pump can be used even for horizontal or heavily deflected boreholes. This means that the DLS is very high. by a special underground bearing housing. There is also a dynamic seal in the well. This movement because the technology of the PCP allows conveying of different of all critical components of the pumping unit phases of a fluid. It also conveyed low volumes of 3 to 20 m3/d belowground has precluded any environmental impact from leaks as efficiently as medium volumes of 10 to 100 m3/d. Since there aboveground. is no pump rod, the pump could be used even for horizontal or The motor that has been selected for the system is a PMM. heavily deflected boreholes; that is to say, the allowable borehole It is designed to meet the specific requirements of a PCP. deviation – the dog leg severity (DLS) – was very high. Eliminating With this slow-speed 10-pin synchronous motor, the specified pump rods rules out rod breakage, as well as friction of rods speed is the same as the actual speed, removing the need against the tubing. This significantly reduced the risk of tubing for complex slip calculations and speed measurements. Even leakage. In addition, it helped achieve higher flow rates in the error-prone, mechanical or magnetically coupled transmission tubing and the use of tubes with a smaller diameter. Pressure can be dispensed with. In this application, even a PCP with an losses in the tubing were also lower. The rods cannot get twisted, aboveground drive is not recommended because of the short which rules out a dangerous backspin – an abrupt relaxation of service life of the overall system. However, the PMM facilitates the drilling line. underground use. As a result of the PMM, the pumps can Other advantages of these rodless PCPs over conventional be installed deeper. They can also be used if there is a high PCP models are a smaller axial load, a larger operating window of deflection. A downhole sensor is installed directly underneath 180 – 500 revolutions, integrated pump and motor protection, and the PMM. It provides data for the operation of the production well the choice of a special, highly xylene-resistant elastomer. Other and data on the machine condition. It also helps to troubleshoot features include an automatic integrated pump control, which problems in the well. For example, it measures fluid and motor serves to start the pump after a power failure, and the remote temperature, as well as pressure on the sensor. This component measurement of real-time pump data for early detection of errors. also allows adjusting of the speed automatically to the pressure, The system also has a smaller footprint than all systems with which prevents the pump from running dry. aboveground drives. Higher flow rates In November 2018, the NETZSCH ESPCP system was installed The design of the ESPCP system, which is installed in northern and put into operation in the oilfield south of Bremen. It had Germany, was adapted to local conditions. It was therefore able to worked without fault until the first unscheduled shutdown of the convey the highly viscous medium, which contains bitumen and production well, which was caused by exceeding external limits paraffin sediments, sand content of up to 40%, or salt deposits, that were not related to the pump. The system was quickly put with a pressure of up to 300 bar. A gas proportion of up to 40% back into service; therefore, the operator planned to purchase of the pump intake did not pose a problem during extraction, additional systems as a result.

November/December 2020 Oilfield Technology | 49


TO P&A Maxim Volkov and Luis Perri, TGT Diagnostics, UK, explain how new advances in through-barrier integrity diagnostics can remove uncertainty and improve success in plug and abandonment and slot recovery operations.

50 |


or all plug and abandonment (P&A) applications, either permanent or for slot recovery, the sealing performance of well system components needs to be assured and remain intact. Well systems are complex and need to work perfectly to perform safely, cleanly, and productively. Understanding the condition and sealing performance of well system barriers can be challenging once the well has been brought onstream, and access to these elements and components is restricted.

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Current mainstream technologies only provide partial answers, leading to an incomplete assessment. However, through-barrier diagnostics look at the well system in a far more holistic and uncompromising way. These technologies are able to see through multiple barriers to provide a more complete picture of the condition of the metal tubulars and the flow around them to see if the seals are holding, prior to P&A. In the case of permanent abandonment, natural barriers that prevent the movement or migration of downhole fluids must be restored. And the performance of the well system barriers must remain intact indefinitely.

In the case of slot recovery, the well components must be in good enough condition to be used again for the upcoming production cycle. A comprehensive integrity assessment is required for either scenario.

Optimising P&A operations

Planning and executing a flawless P&A operation requires prior knowledge of the integrity of the well barriers, and the precise position of all downhole completion elements. Operators armed with this information can determine the location of the permanent plugs and the best depths for the casing cuts for an optimised retrieval procedure. During the productive life of a well, it may experience several operator changes, perhaps after concessions expire or following divestment decisions. This can often lead to historical data being lost which, when it comes to well decommissioning, can increase the potential for making decisions without knowing all the facts about the well system, particularly the position of the casing collars, fins, centralisers, or other components that impede successful decommissioning. Using a simple multifinger caliper or an ultrasound survey, the location of the first-barrier casing collars can be determined, but the locations of the collars Figure 1. Pulse diagnostic platform uses pioneering electromagnetics to provide accurate barrier-by-barrier in the subsequent casing strings assessment of up to four concentric tubulars from a single through-tubing deployment. remain unknown. This approach contains an element of risk and may result in a cut planned directly in line with a thick section of metal, like a casing collar or fin. Cutting across a collar or a fin would mean an increase in the rig and intervention time of several hours, or potentially days. TGT’s Multi Tube Integrity product uses the Pulse electromagnetic sensing platform to provide accurate barrier-by-barrier assessment of up to four concentric tubulars (up to 20 in. dia.) in one single through-tubing deployment. Pulse can also pinpoint to within 1 ft of the location of completion elements. The ‘electromagnetic signature’ of each tube or metal completion component contains information about its wall thickness. The platform harnesses this information and, through 3D Figure 2. Pulse data showing welded fins and collars in 13 3/8 in. and 20 in. casings. modelling, can decipher metal

52 | Oilfield Technology November/December 2020

loss as well as metal gain in multiple casing strings throughout the entire well system. The platform can identify the location of known completion elements but also identify new ones not expected, including welded fins on the outer casing string, often inaccessible to other evaluation technologies.

Case study 1 In a recent operation, TGT’s through-barrier diagnostics were able to help an operator optimise their cut and retrieve operations (Figure 1). The Pulse platform was able to identify the location of all collars and welded fins for the 13 3/8 in. and 20 in. casings (Figure 2). It also provided a corrosion report on all casing strings. The casing cut programme targeted milling the casings 1 – 2 ft below fins across the zone with minimum total wall thickness. The subsequent casing cut and retrieval operation was performed successfully. The correlation of the downhole results and surface inspection confirmed the accuracy of detecting the downhole elements was 1 ft, making the technique suitable for precise determination of the casing cut windows. If the product is used prior to the P&A planning, the diagnostic results would remove the uncertainty, allowing operators to confirm the optimum cutting window location in all casings, thus minimising the intervention time and reducing rig time and costs.

Integrity and corrosion assessment for slot recovery Slot recovery offers operators a way of capitalising on existing assets by providing a new means of extending a well’s productive life.

It is a robust solution which utilises the existing surface and downhole infrastructure to create a ‘new’ offshoot well, which would reduce the costs associated with drilling. However, before this can become a reality, the inspection of downhole completion elements, such as surface casing and its cemented annulus, is a must. Limitations in current technologies have meant that barrier verification is performed while the rig is in place and once the tubulars (production and intermediate casings) have been retrieved. Key input parameters, such as the cement condition and the integrity of the casing, are obtained at the last stage of the planning. The late arrival of this critical information results in a complex well intervention plan, with several contingent scenarios based on a range of potential outcomes from the downhole integrity assessment.

Case study 2 Over in the North Sea, an operator needed a comprehensive corrosion and integrity assessment prior to a slot recovery. The Pulse platform was able to provide a quantitative measurement of the remaining wall thickness of the 5 ½ in. tubing string as well as the remaining wall thicknesses of the 9 5/8 in., 13 3/8 in. and 20 in. casing strings, in one run and with all the tubulars in place, prior to their retrieval (Figure 3). The Pulse platform also confirmed the position of all completion components, including collars, centralisers, and casing shoes in all the mentioned tubulars. The results of this assessment were utilised in the P&A/slot recovery planning.

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Chorus is used to assess the hydraulic seal integrity of the cement barrier to determine where the cement is sealing and where it is not. Fluid flow in the well system creates a rich spectrum of acoustic energy that penetrates the surroundings. This acoustic wave is encoded with information that Chorus can convert into acoustic spectra that can locate leaks and flowpaths throughout the well system, from the wellbore to Figure 3. Pulse data showing wall thickness, collars and completion elements in 5 ½ in., 9 5/8 in., 13 3/8 in. and 20 in. the outer annuli. tubulars. Combined with the Indigo platform, these three platforms The industry is calling for a new solution – one which are part of the company’s True Integrity System, which provides can determine the condition and sealing performance of the a clear diagnosis of integrity dynamics throughout the well cement and the metal barriers, prior to planning the slot recovery. system.

A powerful diagnostic combination

The key to success

The combination of TGT’s Multi Tube Integrity product with the Multi Seal Integrity product utilises the company’s Pulse electromagnetic platform, the Chorus acoustic platform and the Indigo multisense platform, and can be deployed in one through-tubing deployment. Pulse is used to evaluate the metal thickness of multiple tubulars, including the surface casing. It also has the capability of being able to confirm the position of critical completion components, including collars, centralisers, and casing shoes.

It is critical that before slot recovery can be executed there is an understanding of the collective integrity of the tubes, seals, and barriers of the mother well. Only in doing this can there be a guarantee of the secure passage for pressurised fluids. The key to success for any P&A or slot recovery operation is knowing all the facts about the integrity of the well system prior to planning and execution. This delivers the potential to reduce costs, minimise schedule overruns, and ensures the integrity of the final outcome.

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