MAGAZINE | ISSUE 3 2021
Optimize critical well intervention solutions All-new, ultra-compact hot tap unit delivers API 6A-rated performance
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Contents 03 Comment
35 The importance of feasibility studies in coiled tubing drilling
05 World news
Adam Miszewski, AnTech, UK, outlines how feasibility studies can help operators get the most out of technology.
10 Uncertain times for oil and gas Angus Rodger, Wood Mackenzie, Singapore, considers how the oil and gas industry is navigating a time of hyper-uncertainty, and what it means for Asia-Pacific.
17 Safety in numbers James Hardy, Wild Well Control, USA, explains how a range of detailed engineering analyses were used to design a safe drilling diverter system on a gas production platform offshore South East Asia.
20 A tough nut finally cracked Toby Menard and Nigel Rowcliffe, Cudd Pressure Control, USA, and Clinton Moss and Dan Eby, Gunnar Energy Services, USA, explain how the well control benefits of coiled tubing were combined with magnetic ranging technologies to safely and accurately drill a relief well, following several unsuccessful attempts.
25 Running a tight connection Yuri Kolesnikov and Mikhail Efremenko, Gazpromneft-Zapolyarye, Russia, Albert Nurgaleev and Sergey Yakunin, TMK-Premium Service, Russia, and Albert Agishev and Maxim Marchuk, TMK, Russia, examine the application of shouldered threaded connections in horizontal wells.
31 Unlocking tight HPHT reservoirs economically
40 The making of a smooth energy transition Andreas Fliss, Bjørn Tore Torvestad and Elisabeth Norheim, Archer Norway, and David Stokes, Archer UK, discuss how the upcoming energy transition can maximise efficiencies in the oil and gas industry.
44 Drawing a line in the sand Shuquan Xiong, Fan Li, Congda Wei and Donghong Luo, CNOOC China Ltd. Shenzhen, and Mojtaba Moradi, Tendeka, explore how well completion technologies can improve oil recovery, performance and sustainability.
49 Getting out of a hole David Cook and Greg Hauze, Coretrax, USA, look at a circulating sub designed to reduce hole cleaning time and mitigate vibrations.
53 Staying on the dry Shadi Aoun and Manisha Bendbhar, Sulzer Chemtech Middle East, explain how to maintain high performance in triethylene glycol contactors in order to dehydrate gas effectively during reservoir pressure depletion.
58 An extra lease of life Danny Constantinis, EM&I Group, Malta, addresses the importance of keeping existing oil and gas assets going during the transition to renewables.
63 On the ESG path with automated water
Mohammed Munawar, NOV, USA, explains how new frac technology is opening the door to high-pressure, high-temperature (HPHT) reservoirs previously out of reach.
Dean Fanguy, TETRA Technologies, USA, emphasises the ESG benefits for the environment, companies, communities and workers alike that can be reaped from automated water management.
67 Addressing global water production
Front cover As the only hot tap machine in the industry rated API 6A, the brand-new unit from Cudd Well Control delivers high-quality performance at a fraction of the weight. Weighing in at only 85 lbs., it gets the job done when performing critical well interventions on pressurised tubulars to bleed trapped pressure or gain access to carry out remedial work. The ultra-compact design makes it suitable for private aircraft transport and offers fast, nearly effortless deployment, particularly where space requirements might be an issue. Engineered with an 18-in. stroke length, the hot tap unit has a pressure-balanced design for safe, easy operation at up to 10,000 psi and in H2S environments.
Issue 3 2021
Volume 14 Number 03
Kelsey Gonzalez, Valiant Artificial Lift Solutions, USA, outlines how an increasing demand in oil will affect global water production, and how horizontal pumping systems can be used to address this. MAGAZINE | ISSUE 3 2021
71 Subsurface injection lessons Pavel Khudorozhkov, Oleg Sychov and Dmitry Dolganov, AKROS LLC, Russia, and Valentin Tarsky and Ruslan Klishch, Sakhalin Energy Investment Co. Ltd., Russia, consider the findings, issues and lessons learned from the joint re-injection of drill cuttings and produced water into a low permeable formation offshore Sakhalin Island, Russia.
75 Mastering well placement through reinforcement learning
Vidyasagar Ananthan, Beyond Limits, USA, explores how the emerging field of reinforcement learning can help to optimise well placement and field planning in the upstream industry.
Optimize critical well intervention solutions
80 Streamlining exploration
All-new, ultra-compact hot tap unit delivers API 6A-rated performance
OFC OT Issue3 2021.indd 1
Mike Popham, STRYDE, UK, discusses how scaling down the size and weight of seismic nodes can help streamline exploration. 27/08/2021 10:32
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THE WORD IS OUT TETRA Technologies Recognized as Top Performing Service Provider of Completion Fluids With Highest Customer Loyalty
An independent survey of Gulf of Mexico oil and gas operators recognizes TETRA Technologies as the top SHUIRUPLQJ VHUYLFH SURYLGHU RI FRPSOHWLRQ ȵ XLGV ZLWK WKH highest customer loyalty rating. With our PhD innovators, customized chemistries, vertical integration, robust manufacturing capabilities, and service FDSDFLW\ 7(75$ GHYHORSV DQG GHOLYHUV ȵ XLG VROXWLRQV WKDW KHOS PDNH RSHUDWLRQV PRUH Hɝ FLHQW FRVW H HFWLYH productive, and sustainable. 9LVLW WHWUDWHF FRP FRPSOHWLRQȵ XLGV WR OHDUQ PRUH RU HPDLO XV DW FRPSOHWLRQ ȵ XLGV#WHWUDWHF FRP
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Comment Nicholas Woodroof, Deputy Editor
Editorial Managing Editor: James Little
ublime mountains millions of years old, looming over lochs that enthral come rain or shine...Scotland’s natural landscapes certainly made the long, slow car journeys that were a feature of my recent holiday less of a hardship. Scotland is not just a getaway for those keen for a change of scenery after the restrictions on our freedom of movement this past year and a half of course. Come November, the eyes of the world will be on the city of Glasgow as it hosts the pivotal COP26 climate conference. It is likely by then that the country’s government will include the Scottish Green Party, following a power-sharing agreement made with the Scottish National Party in August. The Greens’ power will be limited: pending approval of the agreement by party members, they will have only two ministerial positions in government. Moreover, it is ultimately the UK government in Westminster, rather than the Scottish government, that decides upon the granting of new offshore licences in the North Sea. However, by agreeing to this arrangement the Greens’ leadership must surely believe that they can exert a degree of influence over the course of Scotland’s energy policy. It is now taken as a given that the transferable skills of North Sea workers will see them redeployed on low-carbon energy projects, such as hydrogen and carbon capture and storage (CCS). Readers of Issue 2 of Oilfield Technology will recall an article by KPMG that analysed the results of the latest Aberdeen & Grampian Chamber of Commerce Oil and Gas survey. One takeaway was that a considerable majority of Scottish energy firms surveyed (75%) are aiming to move into renewable projects in the next 3 – 5 years. So, there is clearly a desire to embrace a more diverse and increasingly carbon-free energy portfolio. For example, the Scottish Cluster group, made up of Scottish industrial CO2 emitters and the Acorn CCS and Hydrogen Project partners, estimates that its work could support an average of 15 100 jobs between 2022 – 2050.1 While these numbers are significant, they should be put in the context of a recent report published by Oil & Gas UK that concluded that the various effects of the COVID-19 pandemic on the industry (low oil prices, delayed/cancelled projects and diminished investment) led to 34 700 fewer direct or indirect jobs compared to 2019.2 As of now, Scotland’s emerging, unproven green energy industries – exciting as they may be – are not big enough to offset the recent job losses. The Scottish Greens must therefore be clear-eyed about the consequences of any policies that they may propose, such as an imminent end to oil and gas extraction from the North Sea. As the saying goes, to govern is to choose and there are no shortage of difficult decisions ahead to be made. But to be just and effective, the energy transition has to be just that, a transition, rather than a full stop for Scotland’s remaining oil and gas workers.
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References 1. 2.
The Acorn Project, ‘Scottish Cluster expected to deliver 20,600 jobs in the next decade’, https:// theacornproject.uk/2021/07/21/scottish-cluster-expected-to-deliver-31000-jobs-in-the-next-decade/ (21 July 2021). Oil & Gas UK, ‘Workforce & Employment Insight 2021’, https://oguk.org.uk/wp-content/uploads/ woocommerce_uploads/2021/08/OGUK_Workforce-Employment-Insight-2021-z07os0.pdf (12 August 2021).
Issue 3 2021 Oilfield Technology | 3
Diversion done right the first time
Enventure’s ESeal™ solid expandable mechanical diversion solutions have: • Increased production 700% where cement squeezes failed • Increased flow area 200%, withstanding 10,000 psi • Restored integrity via coiled tubing to save an HP fracture operation Our RF Liner 3.0 is the strongest and highest temp rated mechanical diversion solution in the industry. See the specs and the success stories at env.news/esealtime
Issue 3 2021
Kawa-1 exploration well offshore Guyana spudded Frontera Energy Corp. has announced the spudding of the Kawa-1 exploration well, offshore Guyana. Frontera, which is in a joint venture with CGX Energy, expects the well to reach total depth in the first half of December 2021. The well is located in the northeast quadrant of the Corentyne block, approximately 200 km offshore Georgetown. The water depth is approximately 355 m (1174 ft) and the expected total depth of the well is 6685 m (21 932 ft). The Kawa-1 well targets light oil in combination structural-stratigraphic traps in large Santonian and Campanian slope fan complexes. The primary target is a Santonian sand with updip and lateral pinchout of the reservoir, as well as counter-regional dip and structural closure. The well is also expected to penetrate secondary objectives in a shallower Campanian sand and a deeper Santonian sand with the expectation of targeting additional hydrocarbon potential. The stacked targets in Kawa-1 are considered analogous to the discoveries immediately adjacent to the Corentyne Block, in Block 58 in Suriname. Additionally, the Kawa-1 well is expected to de-risk multiple other prospects on the block that also have stacked reservoirs and similar structural geometries. CGX has also exercised its contractual right with Maersk Drilling Holdings Singapore Pte to use the Maersk Discoverer to drill an additional well.
In brief Australia Santos has awarded the FEED contract for the design, construction and installation of the wellhead platform (WHP) for the Dorado project, in the Bedout Sub-basin, offshore Western Australia, to Sapura Energy. The WHP will be an unmanned installation, located in 90 m water over the Dorado oil and gas field, hosting the development wells and gas reinjection wells with minimal processing facilities, remotely operated from a FPSO facility approximately 2 km away.
ADNOC awards engineering contracts worth US$1 billion
BW Energy makes oil discovery at Dussafu licence
ADNOC has signed framework agreements for concept and FEED services for major projects across its full value chain to support the delivery of its 2030 strategy. The framework agreements – which were signed with eight engineering contractors – have a combined scope worth up to US$1 billion (AED3.67 billion) and the potential for 50% of the value to flow back into the economy of the United Arab Emirates (UAE). The contracted services will be primarily carried out in the UAE. ADNOC signed the framework agreements with AMEC International Ltd. (part of the Wood Group), Fluor, McDermott, Mott MacDonald, SNC-Lavalin International Arabia Limited – Abu Dhabi (part of the Kentech Group), Technip Energies, Worley and a joint venture between Tecnicas Reunidas and NPCC. The agreements will run for 5 years, with an option for a 2-year extension.
BW Energy has made an oil discovery in the Hibiscus North exploration well (DHBNM-1) in the Dussafu Block offshore Gabon. The well is located approximately 6 km north-northeast of the Hibiscus discovery well DHIBM-1 in approximately 115 m of depth. The well will be drilled to a planned total depth of approximately 3500 m. It is expected that the discovery will add to the gross discovered recoverable resource estimate for the block, which is currently estimated to be approximately 105 million bbl gross. During the drilling operations, the Gamba was encountered at a depth of 2794 m and encountered approximately 13.5 m of oil-bearing reservoir in the Upper Gamba sandstone. Determination of the overall hydrocarbon column is pending openhole wireline logging operations, which will be conducted after drilling the well to the planned total depth.
Petrobras has began producing oil and natural gas from FPSO Carioca, the first platform in the Sépia field in the Santos Basin pre-salt. The FPSO is located in water depths of 2200 m. The FPSO, chartered from Modec, has the capacity to process up to 180 000 bpd and compress up to 6 million m3 of natural gas. The project foresees the interconnection of seven producing wells and four injection wells to the FPSO.
UK Maersk Drilling has been awarded a contract with Harbour Energy for the jack-up rig Mærsk Innovator to drill three subsea development wells in Block 28/9 on the UK Continental Shelf. The contract is expected to commence in December 2021. Mærsk Innovator is an ultra-harsh environment CJ70-X150-MD jack-up rig designed for year-round operations in the North Sea. It was delivered in 2003 and is currently warm-stacked in Grenaa, Denmark.
Issue 3 2021 Oilfield Technology | 5
Issue 3 2021
Diary dates 21 – 23 September 2021 Gastech Dubai, UAE gastechevent.com
15 – 18 November 2021 ADIPEC Abu Dhabi, UAE adipec.com
05 – 09 December 2021 23rd World Petroleum Congress Houston, USA 23wpchouston.com
23 – 27 May 2022 28th World Gas Conference Daegu, South Korea wgc2022.org To stay informed about the status of industry events and potential postponements or cancellations of events due to COVID-19, visit Oilfield Technology’s events listing page: www.oilfieldtechnology.com/events/
Web news highlights Ì Ì Ì Ì
Shell contracts Valaris drill ship Magseis Fairfield awarded small size OBN contract in North Sea Production starts from CNOOC oilfield in South China Sea i3 Energy completes acquisition of Central Alberta assets
To read these articles in full and for more event listings go to:
6 | Oilfield Technology Issue 3 2021
Neptune Energy starts production from Duva development
Techouse to perform FEED study for Valhall sulfate removal unit
Operator Neptune Energy and its partners Idemitsu Petroleum Norge, PGNiG Upstream Norway and Sval Energi have started production from the Duva development in the Norwegian sector of the North Sea. Duva was developed as a subsea installation with three oil producers and one gas producer, tied back to the Neptune Energy-operated Gjøa semi-submersible platform. To maximise efficiency, Duva was executed in parallel with the Gjøa P1 development which began production in February 2021. Duva is located 14 km northeast of the Neptune Energy-operated Gjøa field at a water depth of 340 m. Estimated total reserves are 71 million boe, of which 56% is gas. It will add approximately 30 000 boe/d (gross) to the Gjøa facility at plateau.
Techouse will perform the FEED extension study for the sulfate removal unit (SRU) for the Valhall IP platform. The FEED work will be delivered through the Modification Alliance (Aker BP and Aker Solutions). The overall aim is to increase production and extend the lifetime of the Valhall wells by reducing scaling caused by sulfate. The sulfate removal technology provided by Techouse will reduce the sulfate present in seawater before it is injected into the reservoir and remove the potential for sulfate scaling, as well as reduce the formation of hydrogen sulfide. Techouse has already completed an initial study for the delivery and onshore functional testing for the SRU project. The FEED will be carried out during the third and fourth quarters of 2021.
Vaalco signs binding letter of intent for FSO at Etame field offshore Gabon Vaalco Energy, Inc. has announced that its affiliate Vaalco Gabon, SA (Vaalco Gabon) has signed a binding letter of intent (LOI) with World Carrier Offshore Services Corp. to provide and operate a Floating Storage and Offloading (FSO) unit at Vaalco’s Etame Marin field offshore Gabon for up to 8 years, with additional option periods available upon the expiration of the current FPSO contract with BW Offshore in September 2022. The non-binding LOI with Omni Offshore Terminals Pte Ltd., which Vaalco announced in April of this year, expired without any mutually agreeable contract being reached. According to Vaalco, compared to the current FPSO solution the Cap Diamant FSO will reduce storage and offloading costs by almost 50%, lower total operating costs at Etame by approximately 17% to 20% through 2030 and increase effective capacity for storage by over 50%, allowing for greater operational and lifting flexibility and a material reduction in per barrel lifting costs. It is also expected to lead to an extension of the economic field life, resulting in a corresponding increase in recovery and reserves at Etame. The capital investment is projected to save approximately US$20 to US$25 million gross per year (US$13 to US$16 million net to Vaalco) in operational costs through to 2030. The Cap Diamant FSO is a double-hull crude tanker built in 2001. The contract with World Carrier will become effective upon approval from the Etame joint owners, which is expected by early September 2021.
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Issue 3 2021
ABB to provide EPS for Chevron’s Jansz-Io Compression project
PGS finishes survey East of Shetland
ABB has won an order worth approximately US$120 million to supply the overall Electrical Power System (EPS) for the Jansz-Io Compression (J-IC) project. The order, comprising contracts with Chevron Australia Pty Ltd. and Aker Solutions, is booked in 3Q21. The Jansz-Io field is located around 200 km offshore the north-western coast of Australia, at water depths of approximately 1400 m. The field is a part of the Chevron-operated Gorgon natural gas project. The project will involve the construction and installation of a 27 000-t (Topside and Hull) normally unattended floating Field Control Station (FCS), approximately 6500 t of subsea compression infrastructure and a 135 km submarine power cable linked to Barrow Island. ABB will provide the majority of the electrical equipment, both topside and subsea, for J-IC. The project will combine power from shore and Variable Speed Drive long step-out subsea power for the first time. The electrical system will be able to transmit 100 megavolt-amperes over a distance of approximately 140 km and at depths of 1400 m. The contract was awarded following concept development and a FEED study. Work will start immediately and the subsea compression system is expected to be in operation in 2025. Worley has also been awarded a contract to provide detailed engineering, design, and construction management services for the J-IC project’s power transmission and communication components.
PGS has completed the acquisition of a new GeoStreamer X survey in the UK sector of the North Sea over the Kraken field, East of Shetland. Ramform Vanguard acquired the survey, covering two new azimuths of 200 km2, in July 2021. First data will be available in 2Q22. The Kraken field lies in blocks 9/2b and 9/2c within the P1575 license. The reservoir is oil-bearing Paleocene Heimdal sands. Kraken North, Central, and South are produced using an FPSO. EnQuest is the operator and owns a 70.5% interest in the asset. The survey was prefunded by the P1575 group, wth the aim of fully evaluating the development potential of a new western area and nearfield opportunities.
Spirit Energy discovers more gas at Grove field
Strohm to develop TCP for Brazil’s pre-salt
Eni starts production from Cuica field
Spirit Energy has found more gas at the Grove field in the UK North Sea. The Grove North East development well (49/10a-G7) encountered carboniferous reservoir units at the target depth, with around 250 ft (gross) gas-bearing B & C sandstones present. The reservoir quality, sand thickness and gas column height are within the pre-drill expectations and G7 was completed for production. The well was drilled by the Maersk Resolve, a heavy-duty jack-up rig from Maersk Drilling. The Grove field is situated on the UK Continental Shelf close to the UK – Netherlands median line. The Grove field and Grove North East are operated by Spirit Energy (92.5% owner share). Gas from the Grove field is processed at the Markham J6-A facilities operated by Spirit Energy and transported via the West Gas Transport pipeline system to the Den Helder terminal in the Netherlands for further processing.
Strohm has announced a joint industry programme (JIP) with Petrobras and Shell for its thermoplastic composite pipe (TCP) Flowline and Riser technology. The JIP has extended Strohm’s footprint in Brazil, triggering a raft of local engineering appointments and a new Rio de Janeiro office. Brazil’s prolific pre-salt provinces have some of the most productive wells in the world. The JIP builds on earlier work performed in Brazil and commences in August when the company will develop, qualify and test its composite pipe technology with the two operators to make it fully field-proven and commercially available to the oil and gas industry. The programme will manufacture and pilot the installation of two TCP systems, one for TCP Flowlines and the second for TCP Risers. This will result in the industry’s first programme to mature the TCP Riser to TRL-6 (API 17N), proving it is an enabling technology and ready for deployment.
Eni started production from the Cuica field, in Block 15/06 of the Angolan deep offshore, via the FPSO Armada Olombendo vessel on 30 July 2021, just over 4 months after discovery. The Cuica field is located in a water depth of 500 m, approximately 3 km from the FPSO. The early production of the development, which will increase and sustain the FPSO production plateau, includes an oil producer well and a water injection well, tied back to the existing Cabaça North subsea production system. The FPSO has a production capacity of 100 000 bpd and is designed to operate during its production life with zero discharge. Besides Cuica, whose production rate is in line with expectations, the FPSO Armada Olombendo is now receiving and treating the production of Cabaça, Cabaça South East and UM8 fields for a total of 12 wells and five manifolds at a water depth ranging from 400 to 500 m. The FPSO will also receive production from the Cabaça North field in 4Q21.
8 | Oilfield Technology Issue 3 2021
37th Asia Paciﬁc Petroleum Conference (APPEC 2021) September 27–29, 2021 | Singapore & Online The Asia Paciﬁc Petroleum Conference 2021 is back – bigger and bolder. APPEC 2021 will be Platts Asia’s ﬁrst hybrid event where you can tune in from anywhere across the globe as we shape and map the energy future as an APPEC community.
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UNCERTAIN TIMES Angus Rodger, Wood Mackenzie, Singapore, considers how the oil and gas industry is navigating a time of hyper-uncertainty, and what it means for Asia-Pacific.
il and gas is a risky business. Over the years, those risks have been tempered by a single tenet – that oil and gas demand would continue to rise indefinitely. As the energy transition gathers momentum, however, that belief has all but evaporated. The upstream industry now finds itself having to supply oil and gas to a world in which future demand – and prices – are highly uncertain. The range of possible outcomes is dizzying. A gradual energy transition, for instance, could require the industry to invest in new production capacity
for another decade or two. In contrast, Wood Mackenzie’s accelerated energy transition (AET-2) scenario, in which global warming is limited to 2˚C, sees oil demand and prices slide while gas fares comparatively well. On the face of it, that should be good for the Asia-Pacific upstream industry, as over 60% of its 17.2 million boe/d of production is gas. However, the true picture is far more complex, and the implications of the energy transition are already impacting operations across the region in ways that were unforeseen just a few years ago.
For all oil and gas companies – big and small – strategic planning becomes infinitely more complicated when the possibilities of a 2˚C world are incorporated. Wood Mackenzie believes management, as well as investors, need to bear in mind four key things as the upstream industry positions for the challenges ahead:
Business models will adapt to maximise value as the sector matures. Consolidation will expand and bolster margins. Applying the right technology and retaining the right people will determine their success. As the upstream sector tries to navigate these uncharted waters, financial strength will be its life jacket. Even under the AET-2 scenario, upstream is a cash cow; a few more years of firm prices would strengthen balance sheets and make a choppy voyage more comfortable. Whatever happens, upstream will remain big business and provide enormous support to the global economy for quite some time to come.
Capital allocation Capital allocation becomes short-termist. Short-cycle, high-return, low-carbon projects are in; capital-intensive, long-payback oil projects are out. This could lead to under-investment in supply, exacerbating market volatility. Operators need portfolio optionality and agility, so they can adjust to changing market conditions.
Extreme planning, the upstream edition Investment will shift to gas Investment will shift to gas, ending oil’s long supremacy. This shift will occur as gas plays a leading energy transition role. The industry will have to figure out the conundrum of weaker economics if the giant gas projects the world needs are to happen.
ESG issues The industry must tackle environmental, social and corporate governance (ESG) issues head on. The decarbonisation of upstream will prolong the life of the industry and make it more investible; the bond of trust with stakeholders must improve for upstream to retain the social licence to operate.
The AET-2 scenario frames the extreme uncertainties faced by the oil and gas industry as it plans for the future. AET-2 is a scenario, not a forecast, but it shows how stepped-up efforts to tackle climate change could mean a radically different future for oil and gas demand and prices, as opposed to one of continued growth. The oil and gas industry has enjoyed a century of near continuous demand growth. Oil and gas demand, rebounding as the world recovers from the COVID-19 pandemic, is set go beyond the record 160 million boe/d reached in 2019. The world will still need oil and gas supply for decades to come, even as the energy transition erodes fossil fuels’ share of energy. After 6 years of weaker prices, upstream is fitter and leaner than ever. It will generate as much cash flow this year at US$60/bbl as it did at US$100/bbl prior to the 2014 price crash, and there is huge value yet to be extracted.
Continued demand growth for another decade
Figure 1. A wide range of demand uncertainties. Source: Wood Mackenzie Energy Transition Service.
Post-peak demand stays over 90 million bpd out to 2050, encouraging investment in costlier sources of supply and supporting prices just above US$80/bbl (2020, real) by 2030. Gas demand remains strong, with growing coal displacement in Asia underpinning prices of US$8 to US$9/million BTU through 2040 and beyond.
Figure 2. New project returns by resource theme at corporate planning prices. Source: Wood Mackenzie Lens upstream. All averages are weighted by capital spend, economics are based on corporate planning prices of US$50/bbl Brent long-term.
12 | Oilfield Technology Issue 3 2021
Oil demand would peak before 2025 and fall towards 35 million bpd by 2050, 70% below peak levels. By 2030, Brent would average US$40/bbl (2020, real) and continue its decline in the years beyond. Gas demand grows into the 2030s and the declines thereafter would be very gradual, falling to 20% below Wood Mackenzie’s base-case scenario by 2050. LNG prices remain robust at US$7 – US$8/million BTU, before starting to decline post-2040. Gas becomes more expensive than oil on an energy-equivalent basis.
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Capital allocation: an upstream investment playbook Upstream investment has never been for the fainthearted. Projects can take decades from cradle to grave and go through multiple commodity cycles. The energy transition brings a new level of uncertainty. How can the industry deliver the requisite supply and stay profitable, investible, resilient and sustainable? Delivery and discipline are paramount in all aspects of the upstream value chain as the macro environment for oil and gas gets tougher. Oil and gas companies need to send a strong signal to stakeholders that they can be reliable stewards of capital. There are five key things that will influence upstream capital allocation.
Short-termism will reign Projects with shorter payback periods will be prioritised, and portfolios with multiple and varied investment options will be of higher worth. The future will be about minimising unproductive capital and changing tack quickly to mitigate risks. The industry’s affinity for complex, long-life developments with thin margins has to end. The phasing and the rightsizing of projects can help, reducing capital intensity and capturing average costs and prices throughout cycles. However, a world focused on incremental and short-cycle investments suits the US shale business far more than it does Asia-Pacific gas, however resilient regional demand is for the end-product. There is a significant roster of large, high-carbon and
CAPEX-intensive pre-final investment decision (FID) gas projects across South East Asia and Australia that are competing for investment in international portfolios. Many of these projects have been stuck on operators’ books for many years, even decades, without progress. Without significant steps to improve returns and/or decarbonise these projects, the window of opportunity to develop these projects is already rapidly shrinking.
Gas is good Lower full-cycle emissions and the potential to combine with carbon capture and storage (CCS)/carbon capture, utilisation and storage (CCUS) underpins the resilience of gas demand. Upstream capital should flow in that direction. It is not happening yet – absolute spending on oil considerably exceeds gas. Returns are higher from developing a barrel of oil today, with oil production and cash-flow profiles delivering more value upfront. Gas prices are lower than oil prices on an energy-equivalent basis – though in time, this relationship will reverse. Sanctioning large-scale gas and LNG projects is already a big economic and psychological hurdle for many boards. Big gas projects can throw off huge cash flows at high margins once developed, but there is no hiding from their long payback periods and chunky capital commitments. Returns have been low and project execution hard-fought. The stronger outlook for gas demand as a transition fuel supports a pivot to gas, but the industry must find a way to generate acceptable returns from big gas projects. There are far more stalled and stranded gas fields than oilfields scattered across Asia, simply because it is harder to commercialise. A more creative mindset is required and some of the answers come from the oil playbook. The industry is increasingly targeting smaller-scale, shorter-cycle onshore gas projects to improve optionality. But recent Eastern Mediterranean deepwater gas developments have shown that gas returns can be substantially improved through quicker and phased development, if the rocks are good enough.
Decarbonising upstream is crucial Figure 3. Oil versus gas investment split. Source: Wood Mackenzie Lens upstream, global future
projects excluding US Lower 48.
Figure 4. The need for consolidation – the universe of upstream producing companies. Source: Wood Mackenzie Lens upstream.
14 | Oilfield Technology Issue 3 2021
Projects with lower carbon footprints are increasingly attractive, as are investments that decarbonise existing assets. They prolong asset lives, maintain investibility and could capture price premia. The industry needs to shake off the perception that decarbonisation is a cost centre. Carbon pricing will expedite this, but most low-hanging fruit – improved facility efficiency, reduced leakage and flaring – can be value-accretive. For large companies with long-life portfolios, the next step is to think beyond Scope 1 and 2, even if they are sceptical on the pace of transition. One option would be to add more gas to the portfolio, regardless of lower baseline returns. Another would be to scale up both CCUS and CCS – a great opportunity for the industry to leverage its technical expertise and infrastructure and become part of the solution, rather than part of the problem.
THIS IS RELIABILITY BOP Umbilicals Hot Lines
- Faster response times - More pilot lines without increasing the O.D. of the umbilical - Long, continuous lengths - Low volumetric expansion
All Parker Oil and Gas hoses are designed with safety in mind. Parker builds subsea umbilicals, including BOP control umbilicals, with small O.D. velocity hose to allow for precise control and faster response times. Parker hotline hoses for BOP control act as the primary emergency hydraulic control line. If the hydraulic control line of the BOP fails, the hotline shuts down the well valve and triggers the Emergency Disconnect System. In these critical applications, nothing is more important than fast response to ensure the safety of operators.
Asia-Pacific has a leading role to play here, as some key operators – from Santos in Australia to PETRONAS in Malaysia to Repsol in Indonesia – look to develop new upstream CCS projects through this decade.
The largest players will increasingly measure exploration and production investment against solar, wind and other low-carbon investments. Expected returns from oil and gas projects will eclipse those of more predictable renewables for some time, but the relative value proposition will narrow over time.
already being seen, and it is a trend that Wood Mackenzie expects to both continue and expand further afield. Spinouts and joint ventures (JVs) will be created, as uncertainty drives corporate restructuring. At the majors’ level, Big Energy could split into ‘GoodCo’ and ‘BadCo’ along the boundary of new and old energies. Some are already considering separate entities for new energies businesses to test the concept, attract lower-cost capital and win higher valuations. A solution for large IOCs trying to exit non-core areas to improve investment discipline could be to aggregate portfolios in areas such as West Africa or Asia. The new entity would create efficiencies and improve margins. Cash flow would be distributed, but remain at arm’s length of the core upstream operations of Big Energy. This has already been seen: the majors use this JV model in both Europe and West Africa – could it be something equally applicable in Asia-Pacific? The biggest NOCs will gain market share in all demand scenarios. Middle Eastern NOCs have the lowest-cost, lowest-carbon barrels and cheap finance, making them more resilient to change than their international brethren. But any cash-rich NOCs will view uncertainty as an opportunity to acquire assets in a buyers’ market.
Against the tide: finding a buoyant business model
Upstream oil and gas business models will change as the transition gathers pace. One likely outcome of this is that serial consolidation is inevitable as peak demand nears. The pros? Reduced overheads and less competition plus increased efficiency and buying power equals higher margins. The cons? Less innovation, an inability to attract and retain talent and the decision-making inertia that comes with bigger companies. Significant waves of consolidation in the US Lower 48 are
Over the last decade, the industry has traditionally looked to Asian NOCs to be a default acquirer of upstream assets. As the challenges they face change – including corporate and national decarbonisation targets, the development of carbon sequestration expertise and the creation of new energies business units – it seems unlikely they will be as active in the future as they have been in the past.
Exploration is not dead It is still a capital allocation option. Exploration budgets may be smaller and practised by fewer companies, but high-quality, low-cost discoveries can outcompete higher-cost, more carbon-intensive discovered resources. This means more focused exploration than in the past and, by extension, probably fewer exploration wells. If international oil companies (IOCs) continue to step away, national oil companies (NOCs) will become the lifeblood of the sector.
Competition with renewables is intensifying
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SAFETY IN NUMBERS James Hardy, Wild Well Control, USA, explains how a range of detailed engineering analyses were used to design a safe drilling diverter system on a gas production platform offshore South East Asia.
iverter systems are a necessity for drilling wells with potential shallow gas hazards. Conventional diverter designs usually specify that the diverter lines discharge in at least two different directions to account for wind conditions, and that the vent lines have zero or minimal bends and turns to reduce erosion. However, when installing a diverter system on an existing platform, the vent line path may have to deviate significantly from what is considered to be ideal. An engineered solution is therefore required to ensure that this critical well control component is fit-for-purpose should the need arise.
Wild Well Control was commissioned to provide a comprehensive design of a diverter system for a drilling campaign on a shallow water gas production platform in South East Asia. The positioning of the existing production facilities and platform flare and the proposed position of the tender assist barge, along with the seasonal wind patterns, complicated the design of the diverter system. The analyses used to deliver the solution included: worst-case discharge estimates for shallow gas, survey and 3D laser scan of the platform, gas dispersion studies, radiant heat studies, erosion analysis and a blast/explosion study.
Keeping control The diverter system is the annular blowout preventer, vent line(s) and vent line valves. It is commonly used in the initial stages of well construction for diverting an uncontrolled flow of hydrocarbons and associated fluids from a drilling rig in situations where the wellbore and the formation lack sufficient integrity and cannot be safely shut in. The most common application for a diverter is in the shallow sections of a well where the surface casing has yet to be run. A large diameter diverter system allows closure of the drill pipe and preferably includes venting in two directions so as to compensate for wind directions, while diverting wellbore fluids and gases away from the rig. In some cases, line pipe as large as 16 in. is used to vent the flow. In situations where a shallow pocket of gas is located during drilling, for example, shutting in the well may lead to a ‘broach’, causing the formation to fracture and flow to occur outside of the wellbore. The closure of the annulus with the provision of an open outlet directs flow from the wellbore in a safe direction. The purpose of a diverter, therefore, is to limit or avoid a significant build-up of pressure at the surface – if unaddressed, a build-up can lead to hydrocarbons breaking through the short casing and surrounding sediments and reaching the surface, with uncontrollable and potentially disastrous consequences.
Wild Well Control’s specialised engineering team focuses on the deployment of computer-aided engineering, computational fluid dynamics (CFD) and finite element analysis (FEA). Prior to this latest project, the group had performed approximately 20 – 30 gas dispersion studies related to offshore platforms. The platforms in the studies were located in all continents except Antarctica and nearly every major operating offshore basin, including the North Sea, the Gulf of Mexico, Africa, the Middle East and Asia. The design and layout of the asset in South East Asia presented a significant challenge for the creation of a fit-for-purpose diverter solution. A first set of wells had been drilled using a tender assist rig, and the proposed position of the vessel eliminated one of the options for the diverter system’s vent line flow path. In the opposite direction lay the flare boom, which appeared to present an obvious potential safety concern for venting gases. A third direction was subject to prevailing winds for most of the year – another major impediment to the direction of the vent line path. This triple combination of limiting factors represented an extremely rare and complex challenge. The solution was to design a diverter system that would identify the safest flow path route for the vent lines. Neither of the two available options – proximity to the flare boom or in the face of the oncoming wind – would normally be considered ideal.
An engineered response
The gas platform offshore South East Asia also serves as a pipeline compression station, thereby significantly enhancing its risk profile. The platform jacket was in a water depth of no more than 200 m.
The first phase of the project began with an estimation of flow rates and a physical site survey of the platform. Worst-case discharge rates were calculated based on the formation porosity, permeability and pressures. Hundreds of 3D laser scans of the entire asset were taken to create a complete digital visual representation of both the layout and any potential issues, including the positioning of the rig’s equipment, the wellheads and the existing production facilities. This, and access to the rig’s entire geometry from the computer-aided design (CAD) models supplied, helped to ensure the planned diverter infrastructure would be placed in the optimal position to avoid interference with equipment already in-situ. Providing access to the survey online also allowed for a wider range of expert inputs to determine the most appropriate route for the diverter system’s flow path. A 3D model of the platform was then developed. Flame Acceleration Simulator (FLACS) CFD was among the software deployed to create atmospheric dispersion modelling, explosion simulation and other test scenarios. Erosion rate calculations were made using ANSYS Fluent and from 5D bend erosion studies.
Figure 1. Prediction of radiant heat impact on platform from a jet fire.
Figure 2. CFD erosion analysis.
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Analysis Atmospheric dispersion analysis uses calculations and/or simulations to predict the propagation of gas clouds from a blowout, leak or flare. Gaussian plume analysis or CFD determined the concentration of flammable or toxic gases from the source as gas is dispersed by wind and atmospheric turbulence. Wind speed, temperature, humidity and atmospheric stability are accounted for. Results from the analysis can be used in the planning of safe zones and exclusion zones for well control operations, relief well operations and the overall risk of exposing the surrounding areas to a gas cloud. Wind speeds were provided by the client in a site-specific metocean report. Winds at the site were generally consistent from a prevailing direction for most of the year, with a seasonal monsoonal shift whereby the wind direction generally reversed. Explosion analysis provided a study of the severity of an explosion should a gas cloud ignite. Such analysis aims to quantify
the risk to personnel, equipment and infrastructure. Explosion analysis can include both high-level assessments as well as detailed CFD analysis. This analysis is often followed up by an assessment of the effects of an explosion on the surrounding structure.
and connecting that to each well bay, using as few pieces as possible to reduce the potential for erosion. Where there was not a unique line for every well slot, Wild Well Control designed the pipe segments. With support from the client, the company also advised on sizes for the diverter (approximately 29 in.), the annular diverter and the valve on the diverter line. The line was designed with 16 in. SCH 30 pipe (16 in. outer diameter [OD] x 15.25 in. inner diameter [ID]) and 18 in. SCH 120 (18 in. OD x 15.25 in. ID) in the high erosion areas. As well as a comprehensive study that included fabrication and manufacturer recommendations, the detailed design incorporated safety assessments as well as personnel evacuation and shut down times, in compliance with the client’s own safety processes and procedures. Guidelines were provided to the client for the setting up of the diverter’s control system and its correct use by the drill crew in the event of a ‘divert and desert’ situation.
In line with the relevant standards at the time (e.g. API RP 64, Recommended Practice for Diverter Systems Equipment and Operations 2nd edition) a FEED study was undertaken. This included an exploration of the optimal diverter line sizes and calculations of potential erosion rates to determine the optimal position for the diverter. Erosion analysis used CFD to predict the erosion rates in pipework, and equipment carrying particle-laden fluids to assess the integrity of the system. If a fluid flow contains solid particles, then erosion of the walls bounding that flow may occur. This can cause a wide range of problems and is likely to either raise the costs of developing Approved solution equipment – so that they may withstand erosion – or raise the costs Analysis determined that for this particular platform, while the two of operating equipment, because of the need to repair and replace venting options of towards the wind or towards the flare boom had worn-out components. It may even cause both to occur. Erosion can initially appeared less than ideal, allowing the diverter line to be also have significant implications for safety and the environment if vented in the direction of the prevailing wind and on the flare boom the failure of a component or pipeline leads to loss of containment side were actually both within acceptable risk parameters. of hydrocarbons. Gas dispersion modelling provided reassurance to the client The preferable design for a diverter is for the vent line path that the diverter line path would be located at a safe distance from to be as straight as possible, in order to reduce the potential the flare boom and that any gas concentration levels would be for erosion. A surge of shallow gas can contain a range of highly insufficient to enable ignition. The analysis demonstrated that the abrasive materials – including rock, gravel and sand – that can combination of gas concentrations and wind speeds represented a cause significant damage to the diverter system. However, the negligible risk. complexities of the topsides layout on this occasion meant that a As a result of the analysis and design work undertaken, the considerable number of bends and turns in the system would be client was able to safely and confidently proceed with the diverter unavoidable. It was therefore important to fully understand fluid system. and gas flow rates, and design a system that was able to withstand the anticipated erosion impact. Conclusion The next phase of the project included a detailed design of The layout and positioning of a shallow water gas platform in the system. Again, extensive gas dispersion and erosion modelling South East Asia presented a unique challenge when it came to the was undertaken along with radiant heat modelling – to estimate design of a safe diverter system. Initially, conventional wisdom its impact on the platform – and additional thorough structural suggested the only two available vent line paths appeared to carry calculations. significant risk. However, by application of an advanced engineering Radiant heat analysis uses calculations and/or simulations to simulation, it was demonstrated that a safe diverter system design determine the magnitude of radiant heat energy generated by a fire. was achievable. Results of this analysis can be used to determine the level of risk to personnel and/or equipment that are in proximity to a fire or flare. This analysis is often followed up by an assessment of the effects of the fire on surrounding equipment and structure to examine the potential for an event to escalate. CFD modelling enabled a range of calculations to be made, including: a safe location for the diverter vent line exit points, erosion rates at all points along the diverter flow path, how far the diverter line would have to be set from the diverter annular, the impact of sand cuttings on bends from the diverter housing into the line, the assessment of potential erosion bends along the line pipe, the required wall thickness of the pipe in critical sections and the impact of back pressure on the system. Detailed drawings and material recommendations were made for all the vent line sections. With multiple well slots and 16 in. line pipe to take into consideration, the focus was on creating a system that would avoid the unnecessary movement of equipment. This was achieved by designing a fixed section for the diverter Figure 3. CFD simulation of a jet fire from ignition of venting gases.
Issue 3 2021 Oilfield Technology | 19
COVER STORY Toby Menard and Nigel Rowcliffe, Cudd Pressure Control, USA, and Clinton Moss and Dan Eby, Gunnar Energy Services, USA, explain how the well control benefits of coiled tubing were combined with magnetic ranging technologies to safely and accurately drill a relief well, following several unsuccessful attempts.
A TOUGH NUT
FINALLY CRACKED A
lthough independently used to successfully solve problems for many years, it is rare to see coiled tubing drilling and magnetic ranging services combined in operation. Recently, Cudd Pressure Control and Gunnar Energy Services worked together to provide a coherent coiled tubing directional drilling with magnetic ranging service for a successful, time-saving outcome.
Although the body of the salt dome was a large target, the customer wanted to intercept the pinnacle of the structure, adjacent to the original wellbore, to recover all stored product within the structure. The damaged target well was completed with 13 3/8 in., 48 lb casing set at 1902 ft. The last records showed the base of the cavern at 2999 ft. The roof of the cavern was expected to be between 1900 and 1950 ft, with an approximate diameter of 20 ft.
Well history During the 1970s, a well drilled into a salt storage dome in the US became isolated from the wellhead due to a geological anomaly, leaving no practical means of re-entry using the knowledge and equipment of the time. Five decades passed with several unsuccessful attempts to re-access the salt cavern through the existing wellbore. After exhausting all practical options, well control specialists elected to drill a relief well to regain access to the storage cavern.
Innovation in action The relief well surface hole location was 200 ft from the original wellhead. Surface, intermediate and production casings were all drilled and set with a drilling rig. Magnetic ranging methods were used to locate the production casing shoe close to the target in the horizontal plane at an estimated 150 to 200 ft, vertically above the salt dome.
Coiled tubing directional drilling with magnetic ranging was deployed to drill a 6 1/8 in. openhole into the dome apex. Because the historical records of the cavern were close to 50 years old, the inherent well control capabilities of coiled tubing were preferred over the conventional drilling rig to pierce into the storage dome. Crews faced unknown variables as
Figure 1. Coiled tubing directional drilling with magnetic ranging was used to drill a 6 1/8 in. openhole into the dome apex. The inherent well control capabilities of coiled tubing were preferred over the conventional drilling rig to pierce into the storage dome.
to the exact location of the dome as well as the pressures they would encounter, which could vary considerably. Active magnetic ranging methods were not an option for the final section of the relief well drilled with coiled tubing for two reasons. First, the target well casing was isolated/detached from the wellhead, leaving no means of inducing a magnetic signal from the surface. Second, the non-conductive properties of salt meant that injecting current downhole from the relief well – to induce current flow and the associated magnetic field on the target casing – was also not an option. The team onsite chose passive magnetic ranging (PMR) as the optimal ranging solution for the challenging operation. Prior to completing any PMR surveys, crews drilled the 7 in. production casing hardware and formation with a 0˚motor bend setting. Enough formation was drilled beyond the casing shoe to distance the measuring while drilling (MWD) probe away from any magnetic interference from the production casing string in the relief well. With cased bottomhole location based on bit projection and the first section of openhole experiencing magnetic interference, a significant section of unsurveyed wellbore was present. Due to this blind spot and having only an expected 150 to 200 ft from the casing shoe to the cavern top, Gunnar obtained and reviewed all survey and ranging data gained while drilling the cased hole to confirm an accurate starting point relative to the target casing. This additional planning step provided the supplementary information required to intersect the target at the first attempt. Well path planning was critical, considering the short distance available to directionally drill into the target. The cavern entry had to be on target the first time –with no easy method to remedy intersecting the side of the cavern instead of the top. Upon conclusion of the review of all previous directional drilling and ranging data, well control specialists devised a well plan for the coiled tubing drilled portion of the relief well.
The right equipment Cudd provided a one-piece coiled tubing unit, crane, fluid pump and mobile pit system. The blowout preventers (BOPs), choke manifold, separator and flare stack were provided by another contractor. A closed loop system using a saturated brine drilling fluid was established with the separator, dumping brine back to the pits for re-introduction to the system. The coiled tubing unit was furnished with 9000 ft of 2 3/8 in. e-coil installed with 7/16 in. hepta-cable. Cudd called on its Coil Drilling Technologies service to run their proprietary coiled tubing directional drilling bottomhole assembly (BHA). For this specific project, the 3 1/8 in. BHA consisted of a coiled tubing connector, cablehead, check/back pressure valve, hydraulic disconnect, electric orienter, high-precision ranging/steering sensor, gamma ray sensor, non-mag flex sub, 7/8 lobe, 3.0 stage adjustable mud motor with non-mag power section, crossovers and a 6 1/8 in. tri-cone bit. Unlike conventional drilling, the string cannot be rotated. To directionally drill on coiled tubing, the Cudd BHA includes an electric orienter, powered from the surface, to rotate the lower portion of the BHA in either direction to the desired position. Coiled tubing has lower torsional stiffness than drill pipe; therefore, toolface is typically set when drilling as the off-bottom toolface can significantly differ from the on-bottom toolface. In addition, e-coil allows for constant, live downhole data, enabling accurate maintenance of the toolface and continuous monitoring of data from every downhole sensor. Both the Cudd directional team and Gunnar magnetic ranging experts worked side-by-side within the Cudd directional drilling support trailer.
Ranging method Figure 2. The Cudd-Gunnar solution of PMR while coiled tubing drilling
benefits from the inherent ability of e-coil to provide near instantaneous and continuous rapid sampling of the downhole magnetic ranging sensor.
22 | Oilfield Technology Issue 3 2021
PMR makes use of the remnant magnetic field from the target wellbore tubulars to determine the distance and direction between the drilling well and the target well. To measure the magnetic field from the
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target casing, the PMR method typically relies on data collected by the MWD sensor in the drilling well. This method is time-consuming however, as many dozens of measurements are required for a single PMR determination, and it can take several minutes for the MWD system to collect and transmit a single measurement. The requirement of dozens of interspaced measurements also makes the traditional MWD data collection method risky, because the chances of sticking the BHA are heightened due to prolonged periods with minimum reciprocation and rotation of the on-bottom drill string. The Cudd-Gunnar solution of PMR while coiled tubing drilling eliminates these weaknesses, due to the inherent ability of e-coil to provide near instantaneous and continuous rapid sampling of the downhole magnetic ranging sensor. During drilling or when off-bottom, the coiled tubing while drilling ranging systems can collect, process and action data by many more orders of magnitude in a fraction of the time typically achieved by traditional PMR methods. In addition, with high-density and high-accuracy magnetic ranging data readily available at the surface, enhanced modelling techniques can be undertaken. In practice, this novel approach in putting PMR into operation realised significant time savings along with significant enhancements in the accuracy of the ranging results.
Results Using 2 3/8 in. e-coil, Cudd and Gunnar safely and accurately drilled the final section of the relief well into the apex of the salt cavern. Crews completed the rig up of all equipment, including the BHA, the afternoon prior to starting the project. 7 in. casing hardware and rat hole were drilled with a 6 1/8 in. tri-cone bit powered by a 3 1/8 in., 7/8 lobe, 3.0 stage straight housing mud motor. The crew drilled 49 ft of cement before reaching the float collar and shoe. They then drilled a straight rat hole 55 ft beyond the 7 in. casing, where no magnetic interference was observed from the relief well casing. Fewer than 6 hours were needed to complete the procedure, which included trip time and circulating bottoms up twice. Crews performed this process at 3 bpm (126 gpm). Crews switched to directional drilling of the BHA by laying down the straight mud motor and bit before picking up Cudd’s Coil Drilling Technologies BHA. A 3 1/8 in. 7/8 lobe, 3.0 stage adjustable mud motor with non-mag power section and 6 1/8 in. tri-cone bit rigged up after the
bend setting was established at 0.38˚. The proposed well plan required that the well path reduce inclination by 4˚to avoid drilling past the original casing. High side was set and confirmed before nippling up to the wellhead for a pressure test. This step took 3 hours. Initial PMR while drilling was completed along a 34 ft course length when well control specialists onsite determined that a higher motor bend setting was required to reach the ideal cavern target intersection. A total of 3.5 hours elapsed, including trip in and out times. Mud motor bend adjustment to 2.38˚and BHA re-highsiding took a total of 45 minutes from reaching surface to tripping back in the hole. PMR while drilling for an extra 36 ft course length took 6 hours, with additional frequency of stopping for surveys. The PMR survey of drilled wellbore was completed at 1 ft intervals. The BHA was retracted, and the mud motor and bit were laid down. The ranging sensor was left in the BHA and the assembly was tripped back to the bottom so that ranging measurements could be collected as close as possible to the current well total depth. The purpose of this process was to validate and confirm the location before drilling beyond the point of no return. Because of the required time investment, this is not typically a procedural step performed with a conventional drilling rig unless there are concerns over wellbore location. With coiled tubing PMR, the entire process of validating the unlogged interval with high-density surveying took only 6 hours, representing an estimated 90% time savings as compared to collecting data with a conventional drilling rig. With no easy methods of recovery from missing the cavern apex and intersecting lower in the side of the cavern, this additional survey process was time well spent. The high-resolution PMR survey validated the PMR while drilling survey within 0.5 ft. PMR while drilling an additional 51 ft into the cavern apex took an extra 2.5 hours. The final PMR analysis indicates that the relief well intersected the cavern within 4.7 ft of the target well casing, which was well within the 20 ft diameter target provided. The customer had expected the cavern to be full of saturated brine and essentially empty of any previously stored hydrocarbons. The fact that gas was flared for a significant amount of time validated intersecting the top of the cavern. Additionally, the cavern top was expected to be between 1900 and 1950 ft true vertical depth (TVD), whereas communication with the cavern was achieved at 1893 ft TVD.
Figure 3. The increasing magnitude of magnetic field strength, as observed from the MWD sensor, was used in real-time to calculate distance to the target well.
24 | Oilfield Technology Issue 3 2021
The critical and final phase of the relief well was executed with the safest possible approach available to the industry. Along with this high level of safety came an enhancement in accuracy in relative wellbore placement, delivered with an estimated 90% time savings when compared with traditional methods. Having proven the suitability of the technology in a relief well scenario, the Cudd-Gunnar team anticipates an immediate application of the technology in the complex plug and abandonment sector. The introduction of magnetic ranging while coiled tubing drilling in this space promises to deliver a cost-effective step-change in the speed and safety of relief well style drilling interventions.
RUNNING A TIGHT
Yuri Kolesnikov and Mikhail Efremenko, Gazpromneft-Zapolyarye, Russia, Albert Nurgaleev and Sergey Yakunin, TMK-Premium Service, Russia, and Albert Agishev and Maxim Marchuk, TMK, Russia, examine the application of shouldered threaded connections in horizontal wells.
o ensure long-term oil and gas production, the most important element in the well in terms of tightness is the threaded connection. Casing and tubing can be manufactured with standard API (GOST) threaded connections or with special patented premium threaded connections. Standard API (GOST) threaded connections are made with round or buttress threads such as, for example, the Buttress and OTTM types. Such threaded
connections are often called ‘shoulderless’, due to the absence of a torque shoulder. Standard threaded connections only provide liquid tightness, which is achieved by means of a thread-sealing compound. They are easy to manufacture and widely known, although they have limited tensile strength, bending resistance, torque and tightness at medium and high pressures. For the drilling of horizontal wells for hydraulic fracturing such limitations of standard threaded connections are critical. When drilling or completing horizontal wells, the equipment is subjected to combined loads during running-in and operation. Due to the simultaneous exposure to the compressive load, bending load and internal and external pressure, the most critical sections are located in the directional interval. The criteria that influence the value of the equivalent stress are: Geometrical parameters of the well (inner diameter of the cased hole, effective diameter of the openhole, radial clearance between the string and the wellbore wall and the coefficient of friction of the string on the rock).
Ì Ì Ì
Axial resistance forces to string displacement and string rotation. Intensity of wellbore deviation and bending moment. String weight and influence of contact forces.
The axial resistance forces in the string arise from the up/down axial displacement of the string as a result of friction
Figure 1. Profile of UP CENTUM threaded connection.
against the wellbore wall. Work done against these forces causes the following in the string:
Increased compressive forces in the process of transferring the axial load to the bottom of the string. Bending loads when passing directional sections with a high intensity of wellbore deviation. High torque of rotation of the string when running the string with rotation.
The resistance to the movement of the string is determined by the value of the friction coefficient at a given section of the well, as well as by the contact forces arising between the string and the wellbore wall. The most dangerous consequence of the effect of compressive loads is the local loss of longitudinal stability, initially in the form of a flat sinusoid (‘sinusoidal buckling’) which then turns into a spiral (‘spiral buckling’) as the compressive load increases. The excess of the compressive forces over the critical ‘buckling’ loads is accompanied by a progressive increase in the pressing forces in the contact between the string and wellbore wall, which leads to jamming (sticking) of the string and tools in the well.1 ‘Buckling’ is most often observed when drilling and running the string without rotation. An effective way to overcome the increased pressing forces is to run casing with rotation. In this case, the sliding friction coefficients of the string transform into rolling friction coefficients, which makes it possible to reduce the resistance forces to string displacement along the well axis, and to ensure that the design running depth is reached. This method of running the pipe string applies an increased load on the threaded connections. In this case, the threaded connections should withstand the torque generated by the rotation of the string. Based on the above, one of the vulnerable elements in the casing string is the threaded connection, which is limited by the following technical parameters:2 Compression efficiency compared to the pipe body. Allowable bending of the connection. Operating torque.
Ì Ì Ì
Figure 2. Yamburg project well profile.
26 | Oilfield Technology Issue 3 2021
Therefore, selection of the threaded connection is an important criterion for maintaining the integrity of the string and is based on the following basic structural elements:
Ì Ì Ì
Torque shoulder: torque shoulders, in addition to the sealing function, serve to limit axial movement and take up the torque when the casing is rotated. Thread profile shape: to ensure the high strength of the connection under the action of axial and bending loads, hook-shaped or wedge-shaped threads are used. Gas-tight metal-to-metal seal: metal-to-metal sealed connections have one or more seals and feature high tightness under pressure of both liquid and gas. For reliable sealing, sealing surfaces of conical, spherical or cylindrical shapes are used, which provide a tight fit with a given diametrical standoff after the make-up of the connection.
Threaded connection system TMK UPTM CENTUM is a premium quick-assembly connection, qualified in accordance with API 5C5 CAL IV. The connection has a hook thread profile with a pitch of three threads per inch (Figure 1) which, together with the modified cone configuration, provides a deep and easy fit of the pin into the coupling and good make-up at the initial stage of assembly. The strength of the connection is equal to the strength of the pipe body and provides 100% tensile and compression efficiency. The thread provides high gas tightness in extremely difficult operating conditions (extreme combined bending, compressive, tensile loads, torque, aggressive environment). The connection can be used in steam-assisted gravity drainage (SAGD) projects and for cyclic steam stimulation (CSS). The specifications for 114.3 x 7.37 mm Q125 TMK UP CENTUM are: Tensile load: 2134 kN. Compressive load: 2134 kN. Tensile efficiency: 100%. Compression efficiency: 100%. Operating torque: 9600 Nm. Tightness: gas.
Figure 3. Yamburg project well design.
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Application at Yamburg field The Yamburg project is one of Gazprom Neft’s largest projects in the Arctic. Most of its oil reserves are located in the Achimov deposits, which are much deeper and more complex in structure (Figure 2) than the Cenomanian formations from which gas is produced. The main challenges of the project were to select the right technologies to explore and efficiently develop these reserves – using, for example, multi-stage
Figure 4. Simulation of running the 114 mm liner. Axial loads calculation.
Issue 3 2021 Oilfield Technology | 27
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hydraulic fracturing (MHF) – and to drill technologically complex horizontal wells, such as extended reach drilling (ERD) wells. The remainder of this article compares the data obtained from the design calculations with the field data obtained at the well.
Design calculations Using drilling engineering software, a simulation of the 114 mm liner running into a horizontal well was performed. The well data (Figure 3) was: Well bottom: 6500 m. Vertical depth: 490 m. DLS: 2.25˚/10 m. Horizontal section: 1810 m.
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The following calculations were performed: Stress-strain state of string calculation in well. Casing stress analysis to get a rich total horizontal depth. Connection selection that satisfies the calculation results.
Figure 5. Distribution of axial loads along the length of the string.
The results of the axial loads calculation Table 1. Comparison of calculated data and field data along the string while run in hole (RIH) show that running without rotation is difficult to Compression (stuck string), t Operating torque, kNm Interval, m achieve due to the loss of longitudinal stability Calculated data Field data Calculated data Field data of the string (buckling). Part of the liner string 3771 – 4969 3–6t 3–4t is in a compressed state (stuck up to 20 t). If 4369 – 4959 7t 8t 13.5 13.7 running with rotation is applied, the drag force 4969 – 6485 14 t 17 t 14 15.5 is decreased and the string reaches the total depth (Figure 4). The rotation of the string in the well produces an operating torque of up to 14 kNm In the 4969 – 6485 m interval, the liner was run with flushing on the rotary table and 8 – 9 kNm at the liner top (Figure 5). and rotation of the string, the torque on the rotor table Consequently, it is necessary to select a connection torque reached 15.5 kNm, stuck string up to 17 t. capacity that is greater than 9 kNm (to provide string rotation) as At a depth of 5071 m, stuck string up to 17 t, torque on the well as a selected connection that provides gas tightness. TMK’s rotor table was up to 13.7 kNm. UP CENTUM threaded connection meets these requirements. In the 6151 – 6465 m interval, stuck string up to 9 t, the torque on the rotor table increased to 15.5 kNm.
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Comparison of results
At the well in the Yamburg field, casing pipes with dimension 114.3 x 7.37 mm, Q125 grade with the company’s threaded connection were used for running in-hole liner.
Transportation string: 127 mm drill pipes and heavyweight drill pipe: 0-3 171.66 m. Liner: casing 114.3 x 7.37 mm Q125 TMK UP CENTUM, a hydraulic fracturing sleeve and packer: 3771.66 – 6486 m.
The number of rejected pipes during the RIH liner was zero. The total time spent on the assembly and running of the string – including all technological operations associated with reciprocation, flushing and running with rotation – was 75 hours. The pressure test to prove gas tightness was passed successfully.
Before running in, the wellbore was drifted with a 155.6 mm bit and the well was flushed with an oil-based mud (OBM) solution with a density of 1.84 g/cm3.
From the field data, the torque value on the rotary table and the compressive loads in the buckling zone correlate with the design calculation results. The selected string size with the company’s threaded connection corresponds to its declared technical characteristics. The system performs well when the string is rotated with a high torque, saving gas tightness.
Details of the running-in
In the 3771– 4969 m interval, the string was run without rotation, stuck string up to 3 – 4 t (Table 1). In the 4369 – 4959 m interval, the string was run with rotation, stuck string up to 8 t, the torque on the rotary table reached 13.7 kNm.
KURU, E., MARTINEZ, A., MISKA, S., and QIU, W., ‘The Buckling Behavior of Pipes and Its Influence on the Axial Force Transfer in Directional Wells’, paper presented at the SPE/IADC Drilling Conference, Paper No. SPE/IADC 52840, Amsterdam, Holland (March 1999). REKIN, S.A., AGISHEV, A.R., NURGALEEV, A.R., LOBODIN, V.V., and YAKUNIN, S.A., ‘Design of Threaded Connections for Horizontal Well Completion’, Drilling and Oil magazine, September 2020.
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UNLOCKING TIGHT HPHT RESERVOIRS ECONOMICALLY Mohammed Munawar, NOV, USA, explains how new frac technology is opening the door to high-pressure, high-temperature (HPHT) reservoirs previously out of reach.
igh-pressure, high-temperature (HPHT) reservoirs present special challenges. Extracting hydrocarbons from them at economical rates is not possible without durable tools for hydraulic fracturing. A major Middle East operator had a situation that existing tools could not handle – and asked for help. NOV responded by designing and producing the VoyagerTM 15XT OH packer.
Typical, non-typical At a formation’s breakdown pressure, the net applied force exceeds both stress and formation strength. This breaks its rock, allowing hydraulic fracturing fluid to flow inside. Proppant is then placed to hold open the formation while hydrocarbons are extracted. Breakdown pressure differs from one formation to another, and mainly depends on the compressive stress along with formation strength itself. This has been a typical fracturing scenario for some time. Tight HPHT reservoirs are anything but typical. Overcoming formation breakdown pressure in these cases requires a downhole completion that can deliver true 15 000 psi (1034 bar)
differential pressure, withstand stimulation pressures and is able to convey the fracturing fluid.
The challenge A major Middle East operator had used a typical system in some areas of their reservoir. But other areas ran deeper, and their stimulation technique would not work there. They were surprised that they were unable to stimulate the stages even with a 10 000 psi (689 bar) differential pressure system. This scenario was beyond typical. There was very high potential value in the extremely tight reservoir’s HPHT hydrocarbons. But it had been unreachable because of the high pressures. Existing technology simply could not handle the formation breakdown pressures, and they could not economically bring hydrocarbons to the surface. New technology was required.
Requirements of Middle East operator
Figure 1. Voyager 15XT OH packer.
NOV was approached to develop a true 15 000 psi (1034 bar) openhole ball-drop system for the tight HPHT conventional oil and gas operations. The operator specified a series of rigorous technical tests. After technical acceptance, a field trial was commissioned with the following criteria: Installation without mechanical failure. Confirmation that the Flow Lock SubTM was activated and closed during the installation. Proper activation of the frac sleeves during the fracturing operation while applying up to 15 000 psi (1034 bar) differential pressure. Indication that there was zonal isolation and that openhole packers were holding during the fracturing operations. Successful milling of frac sleeves’ ball seats.
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Component research and results Figure 2. Frac simulation test: cycle test, 10 times at 350˚F (177˚C).
Figure 3. GripR OH anchor.
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The company pursued a flexible design for HPHT reservoirs – with the ability to include multiple limited entry. A multi-stage fracturing technique was selected as the ideal method of stimulation. Using openhole packers for zonal isolation and frac sleeves for stimulation to maximise efficiency allowed for continuous pumping operations, and removed the risk of perforation-explosives and multiple wireline runs. In the process, 2 years in design and function testing were invested in order to meet or exceed the operator’s qualifications requirements. The use of company testing facilities in Norway,
Canada and the US proved the robustness, flexibility and reliability of the components and integrated system to produce hydrocarbons at a reasonable cost – on demand.
Frac system NOV started with a solid base: the Voyager frac system had already been deployed and proven in 10 000 fracturing stages in 250 wells around the world. This range of experience in deploying ball-drop systems for various reservoir environments and customers proved crucial in designing and developing the system. The system meets the challenges and needs of both conventional and unconventional HPHT wells. Proper selection of pressure settings and the ball and seat sizing are critical to the success of a deployment. Each component was sized and approved by the customer for this test, with support from the company’s extensive testing and qualification work. The system and its components performed as promised.
Cyclical tests at 15 000 psi (1034 bar) and 350˚F (177˚C) were performed on the anchor, like those required for the Voyager 15XT OH packer. Beyond these, the GripR was set in a 6.125 in. ID fixture and subjected to tensile and compressive loads confirming that it mechanically holds 350 000 lbf (1 556 878 N).
Fracturing sleeve Stimulation requires reliable frac sleeves. The i-FracTM flex sleeve (Figure 4) is a ball-drop-activated multi-stage fracturing sleeve for openhole or cemented completions. Multiple stages can be installed in a wellbore, with each stage containing between 1 to 20 sliding sleeves for optimised fracture design. This allows operational and stimulation flexibility for single- or multiple-point limited-entry openhole assemblies. For each stage, one ball is pumped from the surface to open all sleeves in
Openhole packer The Voyager 15XT OH packer (Figure 1) is a dual-element hydraulically activated packer for 5.875 to 6.125 in. openhole wells. Applying differential pressure against a temporary or permanent plugging device in the casing below sets the packer. Setting pressure can be adjusted through field-accessible shear pins. To ensure robustness, the packer was subjected to the highest standards and testing. It is fully qualified to API 19OH V1 for 15 000 psi (1034 bar) at 350˚F (177˚C). Additional pressure cycling testing was also conducted to simulate worst-case stimulation pressures. Here, the packer element was subjected to 10 cycles of 15 000 psi (1034 bar) at 350˚F (177˚C) and 10 additional cycles at 150˚F (66˚C), in addition to 30 cycles at 260˚F (127˚C) on the body of the packer to simulate multi-stage fracturing operations (Figure 2). All cycles successfully met criteria requiring less than 1% leak off.
Figure 4. i-Frac flex sleeve.
Openhole anchor The GripRTM OH anchor (Figure 3) is run as an integral part of the casing/liner to anchor downhole equipment, creating multi-stage zonal isolation in high-pressure, openhole applications. It has nearly full-circumference, bidirectional slips that keep the liner in place, despite expansion and contraction forces caused by high-rate stage fracturing and production. It is also self-centralising. Furthermore, its full-bore design allows passage of frac balls or plugs for stimulation. The anchor is set hydraulically. First, the Flow Lock Sub plugs the casing below the anchor, then differential pressure is applied at the anchor. Multiple anchors may be run between openhole packers to stabilise the casing during fracturing and production. An anti-preset feature prevents the anchor from setting during the running of the casing/liner.
Figure 5. Flow Lock Sub.
Figure 6. BPS Maxx.
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the given stage. The frac job is then continuously pumped with no preparation time between stages. The flex sleeve was qualified at 15 000 psi (1034 bar) for 10 pressure cycles at 350˚F (177˚C), followed by 15 000 psi (1034 bar) collapse testing from outside to inside. Functionality testing was then performed, including opening the frac sleeve to confirm sleeve opening/activation.
Circulation/lock sub The Flow Lock Sub (Figure 5) is used in multi-zone, openhole completions to allow circulation through the float shoe until it is time to test the casing/liner integrity. First, a ball is dropped or pumped into its seat in the sub. Then, predetermined pressure applied to ball/seat closes and locks the Flow Lock Sub. Pressure integrity is maintained above and below the sub, even if the ball rolls off the seat. Once closed, the casing/liner is tested, and a hydraulically set packer or liner hanger may be set without additional intervention.
Pressure-activated toe port BPSTM Maxx toe port units (Figure 6) are used in horizontal completions, enabling fluid injection at the toe of the well without intervention. This reduces the costs and risks of traditional tubing-conveyed perforating guns or wireline tractors to otherwise gain access to the formation at the toe. They use the same field-proven technology as the standard BPS toe initiation subs used in 20 000 installations. But once activated, the high flow area of a BPS Maxx toe initiation sub supports frac sleeve operations with three times greater injection rates than their standard BPS ports.
The BPS Maxx is fully qualified for applications up to 400˚F (204˚C), with absolute activation pressures ranging from 8000 to 21 000 psi (556 to 1448 bar).
System results In August 2020, NOV deployed the Voyager 15XT frac system as an integrated seven-stage proppant frac trial well. The system’s packer compartmentalised the open hole as designed. The activation ball landed and closed the Flow Lock Sub, helping set the packers and the GripR OH anchor. A pressure test was performed, and the system met the first trial HPHT well criterion. Fracturing stimulation was then performed in October 2020. The BPS toe initiation port was opened, followed by dropping balls for corresponding frac sleeves. Each stage was stimulated, and instantaneous shut-in pressures for pre- and post-fracturing indicated that the packers held during the stimulation, providing zonal isolation. This allowed stimulation at a 40 bbl/min. (6.36 m 3/min.) maximum flow rate in a 20 000 psi (1379 bar) bottomhole pressure environment. Thus, NOV met or exceeded the remaining trial HPHT well criteria and successfully completed the multi-stage stimulation.
Conclusion For challenging HPHT completions, industry operators no longer need to compromise on performance. The company’s new frac system opens the door to target and stimulate reservoirs that were previously out of reach because of higher formation breakdown pressures. Operators can extract hydrocarbons from tight HPHT reservoirs at reasonable costs and desirable flow rates.
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THE IMPORTANCE OF FEASIBILITY STUDIES IN
Adam Miszewski, AnTech, UK, outlines how feasibility studies can help operators get the most out of technology.
earning on the job is a great way of gaining experience, but everyone would be surprised if an airline pilot had not spent some time on a simulator before flying passengers. The reason is that the cost of failure (crashing) is expensive in both human and financial terms. It is much better to simulate events offline. Oilfield operations, where high pressures, hazardous chemicals and complex systems are involved, are no different. Digitally simulating oilfield operations ahead of time saves cost, prevents accidents and speeds up operations. That is why feasibility studies are so important.
The key to getting the most out of technology is understanding when not to use it. After all, the most advanced and cutting-edge technology in the world is useless if it is not used within the correct application. This is especially the case for broad use technologies such as coiled tubing drilling (CTD), which can be employed in a range of applications but are complex in their specifics. For example, CTD can be a low-cost solution in some applications, while in other applications it requires larger investment in order to achieve a greater reward. In remote operations, CTD has the advantages of a low mobilisation cost and a small crew requirement, which maximises return on investment (ROI) by delivering the same production as a conventional rig at a lower overall project cost. However, when drilling a depleted reservoir underbalanced with a two-phase fluid system of water and nitrogen, the spread rate can be higher than a conventional rig operation, but the ROI is realised through achieving production levels that could not be achieved using a conventional rig drilling overbalanced. A sales representative selling a broadly applicable technology such as CTD can seem disingenuous by listing all the potential benefits of the technology, because while these benefits are achievable in the broadest sense, the end client may not actually
realise all of the benefits in every application. It is a case of identifying that the right technology is being used in the right configuration in order to maximise value for the end client. Therefore, any high-quality feasibility study must take into account both the technical and commercial feasibility.
Feasibility studies To illustrate this point, this article will focus on the fundamental steps and points of consideration that would be undertaken during a feasibility study for gas wells being re-entered and drilled, the assumption being that the well should be drilled underbalanced with coiled tubing in order to avoid formation damage, as well as to maximise productivity from the well. A feasibility study can be thought of as a ‘negative proof’. In mathematics, a negative proof is a demonstration that a particular problem cannot be solved as described in the claim. In this case, the claim is that drilling the well using CTD is the technique most likely to maximise success and ROI. In actual fact, a ‘feasibility study’ is quite the opposite of how it sounds, because while something can be feasible it may not always be desirable given the specific circumstances; to ignore that fact would be a disservice to the end client.
Figure 1. Bottomhole circulating pressure (BHCP) and gas production sensitivity to productivity index.
On this basis, the first step is to discuss with the client their rationale for wanting to apply the technology to their field in the first place. The operator understands their fields and their operational challenges better than anyone, and they will have been attracted to the technology based on solving specific problems. A quick phone call can often be enough to gauge whether or not there is a suitable application for CTD or not. At this point, it is also important to answer a few basic operational questions, such as identifying any access restrictions, determining the size of the pad and describing the general drilling experience in the target formations.
Level of detail required
Figure 2. Operating envelope analysis. Tubing performance and productivity for one operating
36 | Oilfield Technology Issue 3 2021
Assuming the project still looks attractive after that first discussion, the next step is to identify the level of detail required from the study, which will determine how deep into the technical analysis to go. Some operators may want an answer as fast as possible, whereas others may require more detailed analysis, even if the result is that the specific project or well is indeed not feasible. This may be due to the fact that they wish to build institutional knowledge around the technology and understand how to evaluate their other assets in-house in order to make best use of the benefits of the technology.
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The core advantage of coiled tubing when drilling is pressure control. Continuous pipe and equipment rated for 15 000 psi wellhead pressure as standard offers a lot more flexibility in terms of drilling both underbalanced and at balance with formation pressure. When drilling underbalanced or at balance on a conventional rig, the rotating control device (RCD) has a much lower pressure rating than the rest of the pressure control equipment. A standard RCD has a pressure rating of 2000 psi static, 1200 psi when stripping and even less when drilling ahead. However, on a coiled tubing unit the RCD is replaced by a stripper that is capable of operating up to the same pressure as the blowout preventers (BOPs) in most instances. Underbalanced CTD (UBCTD) has the safest possible set-up from a well control stand point. In addition, this means that there is much more scope to adjust the well parameters on the fly based on live observations while drilling the hole section, e.g. drilling through a highly productive fracture. The drilling choke is another key piece of equipment on a UBCTD project. Flow from the well is controlled through the circulating fluid and the back pressure provided by a choke. Chokes can be remote controlled and manual or automatic.
UBCTD feasibility study There are four major components to a UBCTD feasibility study: wellbore hydraulics modelling, coiled tubing modelling, equipment specification and cost estimation.
Wellbore hydraulics modelling Prior to working on any hydraulics modelling, a draft trajectory should be made. The trajectory will produce the first set of questions to be answered, which will constrain the well design. For example, can the well be sidetracked and landed within the target formation, or are multiple formations drilled through? Any formation drilled through must be assessed for wellbore stability, and it must be determined whether or not the formations can be safely in communication with each other. At this stage, it will also be possible to start assessing the total project length, and therefore budget, which can be refined as the hydraulics modelling progresses. Once the trajectory has been designed, the hydraulics models are built in a steady-state multi-phase flow modelling software and a critical factor analysis is carried out. This will give an idea of the fluid type and weight that will be used. At this
Figure 3. Production contour.
38 | Oilfield Technology Issue 3 2021
stage, it is important to determine if a single-phase fluid (such as water or brine) will be used, or a two-phase fluid (such as co-mingled water and nitrogen). Once the critical factor analysis modelling has progressed to such a point where some certainty is known about the operational limits of the fluid type and weight and the well productivity, then a tubing forces analysis can be carried out in order to understand the coil size required to achieve the target lateral length. The design of the coiled tubing affects the hydraulic response of the well and vice versa. For example, a larger outer diameter of the coiled tubing will reduce the annular space and therefore increase the bottomhole pressure and the annular velocities, both of which are critical factors to consider in the well design. However, from the other analytical perspective, the injected fluid and the produced gas volumes will affect buoyancy, annular pressures and pump pressures, which will in turn affect the buckling limits, available weight-on-bit, lateral reach, overpull and coil life.
Coiled tubing modelling Once a coiled tubing size has been selected, the models are run in order to determine the relationships between injected fluids, reservoir productivity, circulating rate and wellhead pressure. The primary concern is to address how the well can be kept safely under control during the entire operation. In underbalanced operations, the primary well control is provided by a combination of flow and pressure control equipment and secondary well control is provided by the BOPs. Therefore, understanding the potential gas production is important for understanding controllability, fluid and equipment requirements in order to drill the well safely. In the feasibility study stage, it is particularly important to focus on the extremes. Figure 1 shows analysis at a range of productivity indices, Figure 2 shows tubing performance and productivity for one particular operating condition and Figure 3 shows how well production varies with pump rate and wellhead pressure. Coiled tubing has a distinct advantage in that once stable circulating parameters are obtained then they may be able to be held steady for the entire hole section. This is very important in gas systems where transient effects are difficult to control, but it also prevents overbalanced situations inadvertently occurring and minimises the chance of hole collapse through varying wellbore pressures. One question that may not be intuitive to those not familiar with underbalanced drilling is that, as with the coiled tubing string design and trajectory, there is a limitation on achievable lateral length due to the wellbore hydraulics. It is possible to be underbalanced at the heel of the well and overbalanced at the toe. This is an important factor to take into account, as it is possible to take losses or overpulls at the toe due to poor hole cleaning when the well is producing as expected from the heel. This can be controlled to a certain extent through operational procedures (e.g. flow rates
and optimised fluid weights) and well design (e.g. hole size and casing size). It is clear by now that the nature of UBCTD feasibility studies is for an iteration of the models and design considerations. However, slowly but surely the critical factors are narrowed down. Once the hydraulics models are at this stage, then the coiled tubing models can be revisited for optimisation. With the combination of the hydraulic and coiled tubing models the final achievable lateral reach and well productivity can be calculated. An expected coiled tubing grade and draft design should also be specified at this stage, as this is important both from an engineering stand point but also a cost and durability stand point.
Equipment specification One thing that has not been mentioned so far, but is critical throughout the analysis, is the consideration that must be given to what would happen during real-life operations. A model will provide a solution but experience must determine if that solution is achievable using the equipment and personnel available. ‘What if’ scenarios need to be addressed in the feasibility study, although not in great depth. It is important that the ability to deal with the unexpected is taken into account from the beginning, especially in terms of safe operations. In terms of the equipment required for a UBCTD campaign the major components are the coiled tubing equipment, including pumps, the returns system (e.g. fluids, solids and gas handling) and the directional package. When drilling with a two-phase system, e.g. water and nitrogen, there will be additional pumps, storage tanks and logistics. If the intention
is to push any produced gas to the sales line then consideration must be paid to the maximum nitrogen content allowed and maximum line pressure.
Cost estimation Finally, no feasibility study is complete without a consideration of the cost of operation. As mentioned at the start of the article, the cost can vary substantially depending on the project, technology required and the application. Once the equipment and well design have been completed then a budget for the well can be made. A significant proportion of the costs will be incurred in advance of the project e.g. feasibility studies, engineering design and planning work, coiled tubing purchase and mobilisation. At the feasibility stage it is important not only to give an expected cost, but also to highlight the factors that could cause a variation in that cost and by how much.
Conclusion In conclusion, the four aspects of a feasibility study have been discussed for a gas well drilled underbalanced on coiled tubing: wellbore hydraulics modelling, coiled tubing modelling, equipment specification and cost estimation. By definition, feasibility studies will mean working on projects with significant unknowns and understanding; mitigating or controlling the outcome of those critical factors is most effective when done from the very beginning to ensure that coiled tubing is the right technology for the application. The feasibility study is the first step, and maintaining a heavy focus on engineering design and planning in the early stages of a project maximises the chance of success.
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THE MAKING OF A SMOOTH ENERGY TRANSITION T
he global oil and gas industry is at a turning point as hydrocarbon producers and the industry supply chain, along with the public, are actively moving towards net zero solutions and renewable technologies. Cleaner energy and a reduction in carbon dioxide (CO2) output are becoming key driving influences across the globe. Whilst cleaner energy is in high demand during the transition phase to alternative renewables, there are some key enablers to achieving these goals. These include: Maximising production from existing infrastructure during the transition phase. Minimising operator cost for well abandonment and well intervention for slot recovery and plug and abandonment (P&A).
The oil and gas market has shown remarkable resilience in challenging times over the past few years, and has demonstrated an increasing interest in environmental, social and governance (ESG) metrics as part of achieving the goals of net zero.
Efficient P&A and slot recovery operations The industry has achieved an extraordinary reduction in lowering the cost base over the last 5 – 6 years. Well delivery for offshore wells, which on average accounts for 40 – 50% of the capital spending for exploration and production, is a good starting point to look for improvements. Most operators have tried to curb their capital costs, particularly for what they spend on drilling. Operators have succeeded by focusing on operational improvements, such as reducing non-productive time, optimising procurement practices or by better managing performance.1 For an average offshore oil and gas operator, drilling and completion (D&C) accounts for approximately 40 – 50% of total CAPEX. These costs include different types of wells; production; development and exploration; and plugging and slot recovery. On average, half of this cost is from leasing rigs and the remaining half from equipment, engineering services, consumables and project management. For offshore wells, approximately 70 – 80% of these costs are time-related, suggesting that any compression in delivery time will have a direct benefit on the bottom line.1
Andreas Fliss, Bjørn Tore Torvestad and Elisabeth Norheim, Archer Norway, and David Stokes, Archer UK, discuss how the upcoming energy transition can maximise efficiencies in the oil and gas industry.
Taking P&A and slot recovery operations as an example, the single most time-consuming well activity is ‘tripping in-and-out’ of a well to perform a number of subsequent activities, such as to perform diagnostics, ‘cut-and-pull’ tubing and casing, set and test barriers, as well as casing cut-and-pull operations. The total amount of tripping time is a function of well complexity, well integrity, barrier requirements, number of reservoirs, etc. The combination of downhole activities into single runs in the well therefore yields a significant time-saving potential. To optimise this requires a set of versatile tools and services that can be run in combination with each other. Archer Oiltools does not advocate a single solution, but instead promotes a toolbox of technologies that can address any potential requirement for annulus remediation and casing recovery to address the situation at hand. This provides the most economical solution to the operator whilst minimising the operational CO2 footprint. The company’s technology portfolio includes, but is not limited to, bottomhole assemblies (BHAs) to enable the combination of 3 – 5 conventional downhole trips into a single trip. This includes V0 and V6 ISO-certified suspension plugs, the ability to cut and pull casing in tension, circulate the annulus and address the challenges of settled barite. Cement-thru pipe cutters, Perf Wash and Cement solutions, downhole casing jacks and mechanical perforations along with qualifying shale as a barrier are other solutions offered by the company. With over 350 runs with its X-IT side-tracking system, the company’s slot recovery technology is designed to
maximise reservoir production and optimise production from existing infrastructure. The elimination of downhole trips significantly reduces the total cost of operations by saving rig time, and reduces the environmental footprint by reducing and preventing greenhouse gas emissions. Casing cut-and-pull operations are also one of the most time-consuming well activities typically carried out during P&A and slot recovery campaigns. The time needed for cut-and-pull operations depends on how effectively and quickly the bond between the casing and the material present in the casing annulus can be broken down. Typical cut-and-pull operations consist of cutting a casing section with a tubular cutter and pulling it out of the well back to surface by utilising a casing spear. The challenge is that, on average, only a relatively short casing section can be successfully retrieved, and multiple runs are required to complete the job.
New technology developments Even though the industry has achieved significant cost reductions and efficiency improvements since 2015, COVID-19 and the oil downturn in 2020 have accelerated long-term trends, such as the energy transition and digital transformation. The company is developing new technologies and further expanding its capabilities with a focus on P&A and slot recovery operations to support the industry’s energy transition and its low-carbon targets. The THOR® system is designed to perforate, clean and recover casing, all in a single trip. The method is based on removing friction in casing annulus to recover the casing. The system delivers a step change in performance for pulling the longest casing strings from settled barite. The system is based on the Perforate and Wash technology from Archer Oiltools. The TCP gun system penetrates the first casing without harming the second casing while maintaining the full integrity of this casing. The system can also be configured with a mechanical perforation tool. The system has been applied in multiple wells and has delivered improved performance for pulling long casing strings up to 400 m.
Rig type experience There is a wide range of rig types being used for intervention work, from simple land-based mobile rigs and hydraulic workover units (HWUs) installed on platforms all the way up to semi-submersible rigs and drill ships. The lessons from conducting operations on all types of platforms can be applied to all jobs for optimisation. As an example, the challenges of operating in an extended reach ultra-deepwater well can be applied to a simpler HWU rig where the available energy needs to be used to its full potential due to the relatively low available specifications. Archer has delivered more than 200 combination runs that have successfully saved customers over 350 conventional runs. Doing so has significantly reduced the total cost of operations by lowering rig time and, subsequently, the environmental footprint by reducing greenhouse gas emissions. The following case studies describe in detail challenges, the solution and the results delivered.
Case study 1: multiple cut-and-pull operations in a single trip on a semi-submersible rig Challenge Figure 1. Archer offers solutions to challenges arising during P&A and slot recovery operations.
42 | Oilfield Technology Issue 3 2021
Cutting and pulling of casing from a floating rig poses multiple challenges that normally entail several time-consuming trips. With a
subsea wellhead there is significant tripping necessary to install and retrieve seals and protective equipment. For the cutting sequence itself, the BHA needs to be fixed in the axial direction so that the heave compensators can isolate the movement to allow the cutter to work in the same spot.
Position spear in top of casing and pull to surface.
Result For the comparable offsets, the operation saved 4 days (96 hours) of operating time, which equates to 312 t of CO2 emissions.
The following section describes how such operations can be made significantly more efficient by utilising the appropriate solutions combined into one single trip. A shallow V0-rated plug with ball valve was already installed in a well at the start of operations, and needed to be retrieved. The BHA consisted of a plug running tool, a balanced circulation valve with swivel function, a multi-function pipe cutter and a running tool with wear bushing and seal assembly retrieval function. The BHA was run in hole (RIH) and the wear bushing installed and latched into the seal assembly. The plug was latched on, released and subsequently repositioned to below the planned cut depth. The swivel function in the balanced circulating valve was activated by setting down weight and was, together with the plug, acting as an anchoring point to perform the cut. The wear bushing and seal assembly were retrieved on the way out, followed by re-engagement of the plug at the top of the cut casing. Oil-based mud (OBM) was circulated out behind the casing prior to pulling to surface.
Maximising production from existing infrastructure and minimising costs for well abandonment and well intervention for slot recovery and P&A are two key objectives for operators during the current transition of the oil and gas industry to a more sustainable future. Archer’s toolbox of technologies addresses any potential requirement for annulus remediation and casing recovery whilst minimising the operational CO2 footprint.
BRUN, A., AERTS, G., and JERKØ, M., ‘Oil & Gas Practice - How to achieve 50% reduction in offshore drilling costs’, https://www.mckinsey.com/industries/oiland-gas/our-insights/how-to-achieve-50-percent-reduction-in-offshore-drillingcosts (May 2015).
Result The operation can be summed up through the following savings that were achieved: Pull shallow plug: 3 hours. Installing and retrieving wear bushing: 8 hours. No use of marine swivel for cuts: 5 hours. Pulling of seal assembly: 6 hours. Pulling of casing hanger: 5 hours. Total time saved: 27 hours. Total CO2 saved: 88 t.
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Case study 2: pulling long casing strings from settled barite Challenge During cut-and-pull operations, significant time is often spent on retrieving casing which is stuck in settled barite from degraded mud. The casing pieces often need to be cut into short sections and pulled in multiple runs. Sophisticated methods, such as downhole hydraulic jacking, are also used to overcome the resistance.
Figure 2. Savings (case study 1).
Solution A new method has been developed where the barite can be largely removed prior to pulling the casing, which allows long strings of casing to be pulled out. The method has been applied in multiple wells with good results, and strings of up to 400 m have been pulled out where the benchmark has been in the region of 20 m pieces. The operational sequence for one of the applications can be described with the following steps: Dress of cement plug, tag and pressure test as part of verification and cut casing prior to being pulled out of the hole (POOH). RIH with BHA for perforation of 400 m with spear and cup-type washing tool in string. Perforate and drop guns followed by two washing passes to clean out the settled barite from behind the casing.
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Figure 3. Savings (case study 2).
Issue 3 2021 Oilfield Technology | 43
Drawing a line
in the sand
Shuquan Xiong, Fan Li, Congda Wei and Donghong Luo, CNOOC China Ltd. Shenzhen, and Mojtaba Moradi, Tendeka, explore how well completion technologies can improve oil recovery, performance and sustainability.
he deployment of advanced well completion technologies has become the norm to mitigate early water breakthrough towards the wellbore and improve oil recovery, thereby optimising the performance and sustainability of heavy oil wells. In addition, several studies have acknowledged that such devices act as a type of insurance policy against geological and dynamic reservoir uncertainties to reduce the risk and variation in the expected oil production profiles.1 One such example is an infill development campaign in a thin, heavy oil reservoir in the South China Sea. Tendeka was contracted by CNOOC China Ltd. Shenzhen to mitigate the problems of uneven sweep and water production in a heavy oil, gravel-packed production well. This had not only created an irregular reservoir influx towards the wellbore, but the water mobility in the reservoir was at least 150 times bigger than the oil mobility.
Combining AICDs with sand control solutions The well was drilled in a thin formation in unconsolidated sandstone with an oil column of 4.5 m on average. The large contact area of the 440 m long horizontal well makes the successful exploitation of these reservoirs feasible. As the wells are traditionally completed with screens, gravel pack or slotted liners to control sand production, performing conventional intervention techniques for dealing with excessive water production is a huge challenge. This is due to requirements to perform production logging testing (PLT), followed by squeezing cement or gel, setting plugs and isolating sections with blank straddles/packers. Firstly, this does not guarantee to deliver the optimum solution and, secondly, is associated with high cost, risk and limits, especially for offshore operations.
Deploying autonomous inflow control devices (AICDs), a new generation of the inflow control device (ICD), to manage the reservoir fluid influx towards the wellbore can mitigate such challenges. The active flow control device delivers a variable flow restriction in response to the properties of the fluid and the rate of flow passing through. As demonstrated by many case histories, the introduction of AICDs has proven successful in effectively controlling unwanted fluids. Tendeka has so far deployed more than 150 successful AICD applications in heavy oil formations worldwide.2 In some applications, ICDs/AICDs are deployed into weak sandstone reservoirs that are prone to failure and, consequently, produce sand, so they are frequently combined with a sand control solution, such as gravel packing techniques. This involves pumping a slurry of water and large sand particles/gravel into the annulus between the wellbore and the sand screen completion and allowing the carrier fluid to return via the sand screens, leaving the gravel in place. The current methodology for gravel packing with ICD/AICDs in the well utilises a multiple alpha wave technique whereby at least one conventional standalone screen joint is deployed at the toe of the well to provide a return path during the build-up of the alpha wave. Here, the flow rate is progressively reduced to maximise the dune weight until screen out is observed. Once the gravel packing operation is complete, the standalone screen section at the toe is isolated before the well is placed on production. Conversely, this technique does not allow a complete pack to be achieved and will allow more gravel to build up around the zonal isolation packers. One other possible technique to provide sufficient flow path through the screen assembly is to integrate sliding sleeves into each screen joint but in long lateral wellbores. This may be prohibitively expensive and require multiple, manual manipulations as the wash pipe is retrieved. As shown in Figure 1, the use of a temporary bypass valve is recommended to enable standard gravel packing operations to be performed with (A)ICDs in the completion, without significant additional cost, complexity or compromise. The dissolvable material is utilised with a valve located within the ICD/AICD housing to provide a high flow area path from the annulus to the tubing during completion operations. The FloSure AICD was introduced to function as a standard ICD prior to the breakthrough (proactive solution) and restrict the production of unwanted effluents with lower viscosity after breakthrough, such as water in heavy oil production (reactive solution). Figure 2 illustrates the principal components of the device. The AICD is typically incorporated as part of a screen joint where the produced fluids enter the completion through the screen and flow in the annular space between the screen and the unperforated base pipe into the AICD housing where the device is mounted. Fluids then flow through the AICD into the interior of the production conduit, where they combine with the flow from other zones. As an active device that regulates the flow of fluids, usually by the conversion of potential energy (pressure), it is capable of modifying its control characteristics automatically in response to fluid properties flowing through it. It generates a variable pressure drop based on the size
Figure 1. Gravel packing fluid path with a temporary bypass valve.
46 | Oilfield Technology Issue 3 2021
of the inlet nozzle and on the gap created between a levitating disk and the top plate of the housing in which it is contained. Fluid flow enters the device through the nozzle at the top plate, impacts the disk and spreads radially through the gap between the disk and the top plate, and is then discharged through several outlet ports in the body. Due to its dimensions, the devices can be threaded directly into the base pipe. It is possible to have up to four threaded ports compatible with an AICD, passive ICDs, chemical treatment valves or blanking plugs on each screen joint. This provides a high degree of flexibility for reacting to reservoir uncertainty after drilling and inventory flexibility, as the valve can be mounted or replaced anytime, even at the rig. Dynamic reservoir simulators are required to estimate the production benefits of the AICD over the well’s lifetime. As actual well trajectory and reservoir properties are rarely the same as planned, the actual well is simulated just after drilling with a static near-wellbore simulator to optimise placement of screens, blanks and swellable packers prior to completion.
Well completions and reservoir properties As part of CNOOC’s infill development campaign, wells C1H (completed with gravel pack with stand-alone screens but no AICDs) and C2H are located in the same reservoir formation in the field. C1H is near the oil boundary of the main reservoir and is 400 m apart from C2H (Figure 3). While the C2H well is quite similar to C1H, both in terms of reservoir properties and completions, it was chosen as the analogue well to observe the AICD performance. At the initial stage of production, the water cut of well C2H was approximately 6% and then increased rapidly to 80% in just 3 months, before stabilising at 90%. This is in line with the performance of other wells that were not completed with AICD completions in the field. Well C1H was selected as a pilot well for further AICD applications in upcoming wells in the field. The reservoir pressure nearby well C1H is approximately 13.5 Mpa and a border water aquifer supports the reservoir pressure for both the C1H and C2H wells. The formation temperature is approximately 74˚C, the formation thickness is 7.5 m with an average effective thickness of 4 m and an average porosity of 26.6% (from logging interpretation). The average permeability is 514 mD, the average shale content is 13.6% and the degree of heterogeneity is high. In addition, the reservoir sand is unconsolidated and very loose with a high shale content. As the conventional completion method cannot restrain the influence of mud and sand migration on productivity, it was necessary to gravel pack the completion of well C1H to prevent mud and sand plugging. A dual trip completion was chosen to run for this well. This first allowed gravel packing the annular area between the screens and open hole and then retrofitting an inner string of AICD subs and zonal isolations inside the screens.
AICD completion design workflow An extensive pre-drilling study, including static and dynamic well/reservoir modelling, was performed to investigate the value of using
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AICDs and to determine the strategy for the completion. The objective was to efficiently produce a liquid production rate range of 500 – 3000 bpd over the well’s lifetime. Figure 4 shows the predicted performance of AICDs for the fluid characteristics of the reservoir in a single-phase condition. It demonstrates that the AICD significantly distinguishes between oil and water due to its significant viscosity difference. Within the short period in between reaching targeted drilling depth and running the completion tally in the well, the interpreted real-time log data, e.g. saturation, permeability and calliper data as well as the drilled well trajectory, were used in a static wellbore modelling software to finalise the lower completion of the well. This modelling was involved in simulating several completion designs (various packer placements and AICD numbers) to optimise the well performance. The placement of the packers was crucial to the optimum AICD performance and, subsequently, the added value from the well, as only three packers were practically possible to install.3 The final design was an inner string completion comprising 20 AICDs on 2 7/8 in. subs (one per sub) at four zones compartmentalised with three swellable packers to control water production. Figure 5 shows the design of the installed lower completion, the distribution of AICDs and packer locations. The performance of well C1H with the AICDs, which has been producing since December 2018, has resulted in a significant volume of oil, while the water cut of the well is still only 20% after 12 months of production. This well not only has no problem in terms of sand production, it has also successfully delivered a 200% increase in total oil production compared to the offset well. When comparing actual performance versus the predicted performance of well C1H, it has performed significantly better than estimated, producing an average oil production rate of 713 bpd – 43% higher than the optimistic oil production rate. Over the same period, the offset well with no AICD devices encountered water production in the first two weeks and water cut has kept increasing to 88% (Table 1).
Figure 2. Construction of FloSure AICD.
Figure 3. Well C2H completion schematic.
Conclusion In summary, the combination of AICD devices and gravel pack completions could effectively prevent sand production and control water in the field while improving the oil well recovery rate compared to analogue wells. This would have guidance and reference significance for the development in similar unconsolidated and high argillaceous heavy oil reservoirs, and have extensive promotion value in the field. The project clearly demonstrates the possibility of a successful combination of AICD and gravel packs. AICD completions ensure a balanced contribution from all reservoir sections while significantly limiting water production. In addition, the gravel pack kept the valves and the well safe from the impact of sand.
Figure 4. FloSure ‘TR-7’ AICD performance.
Figure 5. Well C1H completion schematic. Table 1. The performance of wells C1H and C2H after 365 days of production Well name
Total oil production (bbl)
Total water production (bbl)
Well C2H with no AICD
Well C1H with AICDs
48 | Oilfield Technology Issue 3 2021
DOWLATABAD, M.M., ZAREI, F., and AKBARI, M., ‘The Improvement of Production Profile While Managing Reservoir Uncertainties with Inflow Control Devices Completions,’ Society of Petroleum Engineers. doi: 10.2118/173841-MS (2015). MORADI, M., KONOPCZYNSKI, M., MOHD ISMAIL, I., and OGUCHE, I., ‘Production Optimisation of Heavy Oil Wells Using Autonomous Inflow Control Devices’, Society of Petroleum Engineers. doi: 10.2118/193718-MS (2018). DOWLATABAD, M.M., MURADOV, K. M., and DAVIES, D., ‘Novel Workflow to Optimise Annular Flow Isolation in Advanced Wells’, International Petroleum Technology Conference. doi: 10.2523/IPTC-17716-MS (2014).
Note The article is an abridged version of OTC-30403-MS, which was originally scheduled to be held in Kuala Lumpur, Malaysia, 17 – 19 August 2020. The official proceedings were subsequently published online on 27 October 2020.
GETTING OUT OF
O H LE David Cook and Greg Hauze, Coretrax, USA, look at a circulating sub designed to reduce hole cleaning time and mitigate vibrations.
uring drilling of an oil and gas well it is essential that cuttings produced by the drill bit are removed as quickly and efficiently as possible to the surface for disposal. If cuttings and debris are not fully removed from the annulus, it can potentially accumulate in the well and form a cuttings bed around the bottomhole assembly (BHA). This can result in a pack-off, difficulty tripping out-of-hole, trouble moving casing to the
bottom and stuck pipe events, all of which are problematic and costly. Coretrax was contracted in 2020 by an operator in the Permian Basin, US, who encountered issues tripping out-of-hole after reaching total depth on long and challenging lateral wells. The DAV MXTM Circulation Sub was deployed to address the problem, achieving a 70% reduction in hole cleaning time and a 20% increase in cuttings return (Figure 1).
The simple to use, multi-cycle circulating sub can be deployed across a wide range of applications, including hole cleaning, displacements, spotting lost circulation material (LCM) and blowout preventer (BOP) jetting. Activation speed, versatility and robustness enable timely and reliable fast circulating options, without the need of a dedicated service hand.
Hole cleaning in the Permian Basin As suspending cuttings accumulate at the bottom of the wellbore annulus, the flow rate and string rotation are essential to facilitating effective cuttings removal. The operator’s clean-up procedure consisted of on and off bottomhole cleaning and was around 11 hours in duration. Extreme vibrations induced during off bottomhole cleaning were experienced, resulting in costly damage to the expensive specialty BHA equipment. When hole cleaning on or off bottom, the maximum flow rate is often constrained by mud motors, rotary steerable systems and bits. Off bottomhole cleaning is used to increase efficiency; however, this can cause the assembly to experience massive vibrations for extended and continuous periods of time throughout the cycle, as the bit is not engaging the formation. When off bottom, flow area and performance is improved but the risk associated with vibration-induced damage increases. The DAV MX functions through a range of fast activating darts designed to travel quickly and latch and seal in the valve. After reference pressures were recorded, a Split Flow Dart was pumped to seat at 250 gpm. This type of dart is particularly suited for hole cleaning as it splits the flow, allowing fluid to travel down through the BHA while allowing bypass flow through the ports. This allows fluid to circulate around the BHA, alleviating frictional heating caused by rotational contact with the formation while simultaneously boosting annular velocity to maximise hole cleaning effectiveness. A clear pressure drop of approximately 530 psi indicated the dart had landed and the valve opened. The circulation rate was increased, the valve was locked open and off bottomhole cleaning commenced. The result was improved hole cleaning performance, a 20% increase in cuttings observed at the shakers and a 70% reduction in cleanout time.
Multi-tool Figure 1. The DAV MX has applications in drilling, completions, wellbore
clean-up and plug and abandonment operations.
Figure 2. The circulation sub has latch-and-seal technology that enables the darts to latch to the landing seat and maintain a static seal across the valve.
50 | Oilfield Technology Issue 3 2021
The versatility of the circulation sub is due to the available selection of activation darts. When the device is utilised with the Split Flow Dart, between 10 – 25% of the fluid passes down through the BHA and out the bit. The remainder of the fluid is bypassed through the ports into the annulus. Alternatively, if complete bypass of the BHA is desired, the Standard Diverter Dart can be deployed. This dart seals below the ports of the valve, ensuring 100% isolation of the BHA below and all fluid to be directed out of the ports into the annulus. The Permian Basin project used the Split Flow Dart. Here, the fluid passing through to the BHA decreased rotational rate at the bit while increasing annular velocity and debris recovery. This ultimately reduced the magnitude and duration of the vibrations, mitigating BHA damage while increasing hole cleaning performance, without the need for costly chemicals. Another key feature of the tool is its latch-and-seal technology. This enables the darts to latch to the landing seat and maintain a static seal across the valve, and is particularly advantageous for use in lateral and horizontal wells. Notably, the landing seat is made from a ceramic material, which features extremely high
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fracture toughness and abrasion resistance. The ceramic enables the device to accommodate a micro landing profile, which provides the valve with an almost smooth bore. Eliminating significant ID changes maximises the total flow area, and mitigates the risk of debris build-up and inadvertent functioning due to other downhole activation devices. No pressure or function testing is required at the rig, as all valves are seal integrity tested prior to deployment. The robustness of the DAV MX has resulted in its adoption for managed pressure drilling (MPD) applications. The sealing capabilities of the valve have proven valuable when MPD integrity must be maintained. To meet industry and operator needs, Coretrax offers specialty dart-activated contingency float solutions compatible with all configurations. The activation darts can also feature a nose latch that locks the valve open, preventing unintended cycling of the valve. Even when pumping has stopped, the valve ports will remain aligned and the string and wellbore annulus will maintain communication. This pathway ensures pressure is relayed and fluid is continuously transmitted through the ports. This feature is often used for dry tripping, spotting LCM to cure losses, reverse circulation and pressure testing.
to a superfluous, time-consuming and costly redeployment of an activation device. The activation darts are sent out in size-specific colour-coded cartons, outfitted with diagrams, descriptions and associated QA/QC records. This prevents the chance of mix up or confusion of activation device selection commonly associated with balls. The dart application selection has simplified the deployments such that no dedicated personnel are required to operate the technology. Darts can be selected for an application and deployed at a moment’s notice. In a challenging global environment, where personnel and equipment mobilisation can hinder an operation, the usability and versatility of the DAV MX gives operators a multitude of options to address challenges. In addition, because the activation dart can mechanically lock the valve open, there is no need to deploy supplementary devices. The dart functionality is precise and predictable. The activation dart locks open the valve with no loss of total flow area through the ports, maximising the bypass capabilities. The activation darts are comprised of high-grade, precision-machined steel and are designed to perform regardless of fluid density, well depth, hydrostatic pressure or downhole temperature. It has been deployed in the world’s deepest and hottest boreholes, from the deepwater Gulf of Mexico to Iceland’s geothermal wells.
Dart versus ball deployment The company’s dart-activated strings have been deployed in over 2780 wells at depths of more than 31 000 ft and an inclination of up to 98˚. Unlike activation balls, the DAV MX darts are pumped all the way to seat at a constant flow rate, eliminating the need to manage pump rates and strokes (Figure 2). The mechanical extrusion mitigates the chance of blow through, which would lead
Conclusion The company’s dart-activated strings can be used over a variety of applications across drilling, completions, wellbore clean-up and plug and abandon operations. It can be leveraged for stuck pipe contingency, BOP jetting and to regain circulation during pack-off events. Most importantly, it is largely immune to variations in angle, temperature, hydrostatic pressure, mud type and mud weight.
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STAYING ON THE DRY Shadi Aoun and Manisha Bendbhar, Sulzer Chemtech Middle East, explain how to maintain high performance in triethylene glycol contactors in order to dehydrate gas effectively during reservoir pressure depletion. il and gas reservoirs face a decline in pressure over time, leading to reduced production rates that may make the extraction of resources economically unsustainable. If there is not enough energy in the form of reservoir pressure to overcome surface and hydrostatic pressure in the wellbore, hydrocarbon gases and liquids will not flow to the surface, regardless of their volumes in the reservoir. The average life span of an oil or natural gas well is usually 20 to 30 years. However, new
technologies are being developed to extend this. Extraction from a mature well is usually improved by applying traditional enhanced oil and gas recovery (EOR/EGR) technologies. Over recent years, alternative solutions have been offered to improve recovery rates further. This article explains the impact of well pressure depletion on the performance of triethylene glycol (TEG) contactors, as well as how high efficiency and capacity can be maintained by upgrading the contactor’s internals.
contactors is mostly equipped with structured packing, such as Sulzer’s MellapakPlusTM or MellaGlycolTM. An outlet scrubber mist elimination section to avoid entrainment of free TEG droplets along with the dry gas and to minimise TEG losses. The required type of mist eliminator depends on the F-factor of the contactor. It can be a wire-mesh mist eliminator, such as the company’s KnitMeshTM 9797-GLYCOL high performance pad, or an advanced mist eliminator – such as the MKS Multi CassetteTM – if higher capacity and efficiency are required. An inlet scrubber mist elimination section to remove free liquids, such as hydrocarbon condensate or free water, from the feed stream prior to it entering into the absorption section. Similarly to the top mist eliminator, the inlet scrubber is designed either with a wire-mesh pad, MKS Multi Cassette or axial cyclone deck, depending on the prevailing conditions and vessel gas load factor in this section.
Gas dehydration is a key task, as water in natural gas can lead to various operational issues downstream. If the temperature in the gas transmission pipe falls below the dew point, the water starts to condense on the pipe’s inner surfaces and the following problems can occur: Formation of methane hydrate, which can affect the pipeline and its fittings, i.e. by plugging valves, coolers or other equipment. Sour natural gas dissolved in condensed water causes corrosion, which can be amplified in a combination of hydrogen sulfide (H2S) with carbon dioxide (CO2) or other acids, such as acetic acid. Reduction of gas calorific value. Operational issues in downstream natural gas liquid (NGL) cryogenic plants.
The most widely used method for the large-scale dehydration of natural gas is water absorption, using TEG as a solvent. Dehydration with TEG is a regenerative absorption process. Generally, it includes a high-pressure absorption column (contactor), where gas at high pressure comes into contact with a liquid stream of lean glycol. After absorbing the water contained in the gas, the lean glycol becomes rich glycol, which is fed to a regeneration unit to remove the absorbed water. In most modern gas dehydration units, the TEG contactor column consists of the following: An absorption section, where water is absorbed into the TEG solvent from the wet gas. The absorption section of new
In some gas dehydration units, the inlet scrubber is designed as a separate upstream vessel, while in other units it is integrated into the bottom section of the TEG contactor, above the feed inlet device and below the chimney tray. Inadequate performance of the inlet scrubber can lead to free hydrocarbon condensate carryover into the contactor section, causing foaming and oil skimming problems. It can also lead to operational issues in the regeneration system, which can create bottlenecks and reduce the gas handling capacity of the entire unit.
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Figure 1. BXPlus packing.
Impact of reservoir pressure depletion on TEG contactors In order to increase production from both oil and natural gas wells, companies should utilise a proper reservoir pressure maintenance system. Various production enhancement methods are available, such as EOR/EGR, water flooding and gas injection. These activities usually impact surface production facilities, especially the gas dehydration unit. The gas can be more highly saturated with water at the reservoir temperature and pressure. In addition, the amount of heavier hydrocarbons in the wet gas can be elevated. Furthermore, in some cases, the decrease in well pressure can reduce the TEG contactor’s operating pressure, which leads to an increase in the actual gas volumetric flowrate needed to maintain a constant gas production rate in million standard ft3/d or million standard m3/d. Underground gas storage in depleted fields, flow-line looping and gas lift capacity can also impact surface production facilities. The existing inlet scrubber and TEG contactor internals have to be carefully evaluated to make sure they can handle the aforementioned conditions, including changes in the total water and hydrocarbon content. In principle, efficiency and capacity can be restored by upgrading the internals.
Mist eliminators at inlet and outlet scrubbers
Figure 2. MKS Multi Cassette mist eliminator.
54 | Oilfield Technology Issue 3 2021
Generally, both inlet and outlet scrubbers are designed with wire-mesh mist eliminators. KnitMesh mist eliminators have been applied successfully as a low-cost and efficient method for the removal of liquid droplets from gas. They have a limited capacity and can provide good liquid removal performance up to a design gas load factor of 0.35 ft/s (0.107 m/s). Due to the drop in operating pressure caused by well depletion, the gas load factor in the inlet and outlet scrubbers can increase. The gas load factor may even exceed the recommended operating conditions of wire-mesh designs. As a result, the liquid removal efficiency can deteriorate.
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Highly efficient liquid scrubbing of the wet gas feed stream is needed to minimise the carryover of significant volumes of hydrocarbon condensate into the glycol contacting section, as this can cause different operational issues in the unit. Similarly, in the outlet gas scrubbing section, the mist eliminator must remove most of the free entrained TEG droplets in the dry gas to minimise glycol losses and control solvent consumption. The MKS Multi Cassette mist eliminator offers a reliable solution to overcome the potential bottleneck presented by wire-mesh mist eliminators, while maintaining high separation performance in the inlet and outlet scrubbers. It consists of an axial cyclone element followed by a number of separating cassettes mounted above it. The induced centrifugal force in the swirling element will initiate a pre-separation of liquid being collected in the bottom cassette. The gas then passes radially through the cassettes. Each one is equipped with multiple layers of wire-mesh packing that efficiently separate the remaining droplets by both direct and inertial interception. The liquid collected is drained through an elaborate system inside the cassettes to the main collection and support deck of the system. From there, the liquid passes through drainpipes to the allocated liquid compartment.
Absorption section A reduction in operating pressure increases the humidity in the wet gas feed stream, and the existing absorption internals might not be sufficient to achieve the targeted water dew point in the dry gas. In addition, the F-factor (gas load factor) increases, limiting the capacity of the existing absorption internals. Existing TEG contactors are generally limited by their vessel diameter and the available height for the mass transfer equipment, as well as by the lean TEG circulation rate and the level of lean TEG purity achieved in the regeneration unit. When higher capacity or efficiency is required, the existing absorption internals must be replaced with new ones that can provide a higher number of transfer units (NTUs) over the
Figure 3. Natural gas dehydration with TEG.
56 | Oilfield Technology Issue 3 2021
available installation height while being able to sustain the capacity and pressure drop within acceptable limits. Sulzer’s BXPlusTM packing can offer a solution for such a retrofit. When compared to conventional sheet metal packings, the number of transfer units per metre (NTUM) of BXPlus is significantly greater while creating an optimum balance between the NTUM and achievable capacity.
Case study Background A major gas operator in the Middle East asked Sulzer to upgrade its processing equipment. Due to foreseen pressure depletion in its wells, the TEG contactor’s operating pressure was reduced by 30%, from 1740 psi to 1230 psi (120 bar to 85 bar). The existing TEG contactor was equipped with Sulzer MellapakTM 250.Y structured packing – which had been operating for several years and could be upgraded – as well as a conventional mist eliminator in the inlet and outlet scrubbing sections. The outlet gas water content needed to be maintained below 3 lb/million standard ft3/d (approximately 50 mg/Nm3). The operating pressure decrease was affecting the dehydration process parameters: The feed gas humidity had increased by 25%. The existing structured packing was not sufficient to achieve the required NTUs and to meet the dry gas specification. The gas density was reduced from 6.87 lb/ft3 to 4.37 lb/ft3 (110 kg/m3 to 70 kg/m3). As a result, the TEG contactor needed to be able to handle an increase in the gas flow capacity of approximately 45%.
Modifications Gas inlet section Based on the above changes, the inlet momentum through the feed nozzle was increased by approximately 45%. The existing contactor was equipped with a gas box (deflector type). To minimise shearing and re-entrainment of liquid droplets in the feed, the existing inlet deflector had to be replaced with a Shell SchoepentoeterTM inlet device. The purpose of this was to decrease the momentum of the feed in a highly controlled manner, effectively separating the bulk liquid and achieving an even distribution of vapour over the TEG contactor’s cross-sectional area. To cope with the high inlet momentum and provide the necessary mechanical integrity, the Schoepentoeter inlet was reinforced with specially designed structured elements. The design was also verified using finite element analysis (FEA).
Inlet scrubber The existing TEG contactor had an integral inlet scrubbing section equipped with a conventional KnitMesh mist eliminator. The gas load factor in the inlet scrubber was increased up to 0.49 ft/s (0.15 m/s), which exceeded the tolerable allowance for the wire-mesh pads, causing flooding of the pad. Due to very tight spacing in the scrubbing section, the replacement of the wire-mesh mist eliminator with a MKS Multi Cassette or an axial cyclone deck was not suitable in this instance. To overcome the height limitation, the existing TEG collector chimney tray above the feed inlet was modified to accommodate Sulzer HiPerTM axial cyclones in the risers of the chimney tray. The existing conventional mist eliminator was replaced with an improved Sulzer KnitMesh 9798 pad, which acted as a droplet agglomerator for the downstream axial cyclones while offering sufficient mist elimination for the turndown cases.
Absorption section with structured packing As the humidity in the feed gas was increased by 25%, the existing structured packing Mellapak 250.Y could not achieve the required NTUs to meet the required dry gas specification. To achieve the required dehydration efficiency, the existing structured packing was replaced with a newer, high-efficiency Sulzer BXPlus. This modification supports the existing packing height, which could not be increased. Furthermore, the necessary lean TEG purity and circulation rate could be maintained. Finally, major modifications in the regeneration unit or any other equipment, such as pumps and heat exchangers, were avoided.
The lean TEG gravity liquid distributor was replaced with Sulzer’s MellaTechTM liquid distributor to improve distribution quality.
Top mist eliminator (outlet scrubber) The existing outlet scrubber contained a conventional KnitMesh mist eliminator. The gas load factor in the outlet scrubbing section was increased up to 0.4 ft/s (0.12 m/s), which exceeded the recommended operating conditions for wire-mesh pads. Therefore, the existing pad was replaced with an MKS Multi Cassette mist eliminator.
Installation of modified internals TEG contactors are operated at high pressure, and any welding onto the vessel wall would require post-welding heat treatment and column re-certification. This would not only result in prolonged shutdown times, but would also require large volumes of water for hydrotesting of the vessel. The new internals were therefore installed using expansion rings, which do not require any welding; this meant the overall installation time was shortened. Moreover, none of the existing column nozzles required any modification.
Conclusion The gas operator’s TEG contactor was successfully revamped to handle the 45% gas capacity increase and 25% greater humidity in the wet gas, achieving the dry gas specification without any hot work to the existing column shell. The time required for such modifications was approximately 7 days, allowing the client to quickly benefit from the new set-up.
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An extra lease
h lif he life extension t i off existing i ti fl floating ti production d ti units it (FPSO (FPSOs)) iis iincreasingly i l iimportant, t t as hydrocarbon supply shortages are evident and the construction of new and converted assets will take time. Most FPSOs are converted very large crude carriers (VLCCs), so the hull and many of the marine systems are as old as the vessel itself. According to the American Bureau of Shipping (ABS) – which is one of the main classification societies for FPSOs – 25% are over 40 years old, and 70% are over 20 years old, so there may well be an increasing demand for life extensions of oil and gas-producing assets over the next few decades while alternative and renewable energy sources come online.1 It may take some years before renewable energy makes a big difference to the need for hydrocarbons, and during this transition the hydrocarbon-producing assets will of course need to be maintained. Floating offshore wind (FOW) is one of the renewable sectors that will make a significant impact and will undoubtedly progress, despite the challenges of adequate port and manufacturing facilities, supply chain development and an established regulatory framework.
Danny Constantinis, EM&I Group, Malta, addresses the importance of keeping existing oil and gas assets going during the transition to renewables.
Nevertheless, FOW and most renewables need to deal with the question of energy storage, and until this is resolved there will be a need for back-up energy and therefore the need for hydrocarbon supplies for some time to come, bringing the question of life extensions to the fore.
A lack of expertise and skills
Figure 1. NoMan cargo oil tank.
This leads back to the question of the practicalities of life extensions for ageing assets, both for executing the modifications and for continuing to operate the assets with a diminishing resource of people and service providers, noting that many will have transitioned to the renewables sector. Fortunately, much of the technology required for ageing hydrocarbon producers will be similar to that required for FOW assets. This is because the industry drivers of using robotics and data to ensure improvements in safety, cost and efficiency will apply not only to newly constructed assets but also to older operating assets and the upcoming FOW units. Conventional life extension strategies may have to change to take on board these new requirements, and this creates challenges in adapting modern integrity techniques to extending the life of older designs. For example, a life extension study might well look at the fatigue or corrosion remaining life and develop plans to replace or protect structures and pressure systems for a further period; ‘soft issues’ such as maintaining, upgrading or replacing control systems may be much more difficult however. As an industry, there is wide experience of doing this kind of work, but when the scope includes such challenges as ensuring that the life-extended asset operates with minimal people on board (POB) – using robots to inspect and maintain the asset – then a different approach is required.
Designing life extensions with robotics in mind
Figure 2. ExPert.
In some ways, life extension projects offer an opportunity to bring in new technology that improves safety and efficiency, and indeed some of the practical life extension execution work can benefit from robotics and improved use of data. EM&I has led a joint industry project (JIP) on behalf of the Global FPSO Research Forum for the last 8 years called Hull Inspection Techniques and Strategy (HITS), which has stimulated some innovations and technologies that can be used on all floating assets, including those planning a life extension. Recently, some of this technology was adapted to carry out underwater hull repairs (normally requiring the FPSO to drydock), to be implemented on station and without either production interference or use of divers.
Better for the environment
Figure 3. HullGuard impressed current cathodic protection installation.
60 | Oilfield Technology Issue 3 2021
Many similar technologies can be designed into life extension projects that make the asset safer and more efficient. They do not require divers or put people at risk in hazardous areas, such as working at height or in confined spaces. Some of the robotic and digital technologies that have been stimulated by the HITS JIP include the ODIN® diverless underwater inspection and maintenance systems and the NoMan® rapid robotic surveys of confined spaces. The next stage of HITS will study robotic and risk-based methods to minimise the need to clean tanks prior to inspection. Other technologies that reduce safety risks and costs include ANALYSETM data analysis methods that halve the need
to put POB for pressure system surveys; ExPertTM, which is a non-intrusive and remote method for Ex equipment inspections; and HullGuard®, which is a diverless hull corrosion protection system.
Remote inspections and autonomous vessels Resident robots and autonomous vessels will play an increasing role in improving efficiency and safety, so that relevant experts and class society surveyors will not need to visit the offshore assets concerned. This also saves on POB and helicopter trips, which in turn reduces costs and carbon emissions. It may also help with the inevitable diminishing number of skilled personnel available who are familiar with such assets, as the target of net zero by 2050 draws closer. Robots and innovative methods can make hull repairs and renewals much safer and simpler. In addition, ODIN access ports can be used to drill through the hull adjacent to the repair area from within the hull, enabling wire guides to be passed to the outside of the hull, taken to the surface by a remotely operated vehicle (ROV), which is effectively a robot, and connected to a cofferdam that is winched into position over the area to be repaired. The ROV can observe the whole process from outside the hull and advise the technicians operating the winches inside the hull when the cofferdam is in position. The hull repair can then take place, and on completion the cofferdam is released and returned to the surface. Extensive repair projects have already been carried out successfully for a supermajor and leading FPSO operators. This type of technology allows assets to remain on station, on hire and in production while the repairs are carried out, so it is an important development for the life extension of ageing assets. Isolation valves are often as old as the vessel itself and repairs are often complex and time-consuming, so early detection of leaks or problems with seals is vital for efficient operation. The ODIN technology allows the operator to literally see the valve opening and sealing in real-time and while in operation. Early warning of problems can then be resolved again using robotic systems to clean or replace the valves.
The question of cost and risk is always a feature of using new technology, but these systems are thoroughly tested and accepted as a means of improving safety to as low as reasonably practicable (ALARP) a level. Thus, these are viable alternatives for avoiding the risk to human life and indeed reducing the number of personnel exposed to risk.
The need for regular inspection The thousands of electrical (Ex) components in hazardous areas on FPSOs need regular inspection, which normally involves isolating the electrical systems before dismantling the items for inspection and then reassembling them. This is a slow and expensive business, with the risk of introducing errors during dismantling and reassembly.
Figure 4. Hull side shell repairs.
Confined spaces Storage tanks and other confined spaces, including pressure vessels, can also be inspected without manned entry using the NoMan remote camera and laser scanning technologies. The camera system is now ATEX (Ex) rated, so does not require tanks to be prepared for human entry, gas freed and vented before it is inserted through deck openings for both general visual inspection (GVI) and close visual inspection (CVI). The camera has its own lighting, can pan, tilt and zoom, and is mounted on articulated carbon fibre manipulators that can be used at any level and articulated in the tanks to view the structure from different angles. The laser scanners are deployed on stabilised robotic systems that access the confined spaces generally through existing access holes in the tank or pressure vessel. NoMan is a class-approved system capable of detecting and measuring corrosion, distortion, pitting and coating damage, and can also take thickness measurements, meaning that the system provides vital information without the need for manned entry.
Figure 5. ODIN valve inspection.
Figure 6. Aseng laser.
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Alternative methods have been developed using both operational data to inform electronic management systems that optimise the integrity process and remote/robotic tools that are safer, faster and more economic. The ExPert system uses portable scanners and remotely operated cameras that can ‘see though’ the items concerned and allow the operators to identify any anomalies. Visual inspections can be carried out without having to work at heights and the system does not require electrical systems to be isolated during inspection. The digital data is rapidly fed into the system, allowing quick intervention where necessary.
inspection, cleaning and/or replacement at any time from within the hull.
Pressure systems need special attention, so normally require numerous ultrasonic thickness measurements (UTMs) to be taken on a regular basis to meet class requirements. However, the ‘hit rate’ for finding anomalies is less than 5%, so again industry has worked to find a better way to tackle this problem. Using extensive historic data and in partnership with leading universities a statistical approach has been developed called ‘ANALYSE’, which safely reduces UTM workscopes by up to 50% yet delivers better insights into the condition of the pressure system.
Keeping existing oil and gas assets going during the transition to renewables is essential. It will be challenging, as the expertise and experience required will be in short supply, so new technologies are being developed that minimise the risk to people by using robots to efficiently carry out the dangerous work and obtaining of data. Fortunately, many of the emerging technologies described will also be applicable to FOW and other renewable energy sources, making the transition itself efficient. Oil and gas will still be required for the numerous by-products and lubrication, but in much smaller quantities. There will, therefore, be a need to keep some assets going beyond 2050 and net zero, but this will probably become a ‘specialist’ market and only economic sources will be considered.
Installing anodes without using divers Many ageing FPSOs need their anodes replacing to protect the hull from corrosion. This was a challenge without using divers, so the ODIN access ports were adapted to allow retractable HullGuard anodes to be inserted through the hull and connected to an impressed current cathodic protection (ICCP) system. This has been successful because the anodes can also be retracted for
Mooring chains Mooring chains also need to be cleaned and inspected during periodic surveys to ensure that the chains are in good condition and the links have not suffered excessive wear or damage. This is currently being done using ROVs equipped with cavitation cleaners and callipers, but new technology is being tested that is designed to inspect and maintain the full length of mooring chains autonomously.
American Bureau of Shipping webinar, ‘Driving Safety and Reducing Risk: FPU Life Extension’ (11 March 2021), https://absinfo.eagle.org/acton/fs/blocks/ showLandingPage/a/16130/p/p-025c/t/page/fm/0
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ON THE ESG PATH
WITH AUTOMATED WATER RECYCLING Dean Fanguy, TETRA Technologies, USA, emphasises the ESG benefits for the environment, companies, communities and workers alike that can be reaped from automated water management.
mong the many outcomes of the COVID-19 pandemic for the energy industry over the past year and a half has been an intensified push to adopt more sustainable environmental, social and corporate governance (ESG) practices. As reported by Reuters and Morningstar earlier this year, investment in funds focused on ESG shot up by 29% to almost US$1.7 trillion in 4Q20.1 With ESG concerns now enjoying widespread currency among investors, its three measures of sustainability have shifted from optional to essential for the reputation and financial health of corporate enterprises. Of course, ESG policies were already making inroads, but the pandemic seems to have deepened resolve among investors and accelerated the pace of adoption among company leaders. Two prime examples of ESG practices with substantial impact in the oil and gas sector are the recycling of produced and flowback waters and automating water management.
Recycling produced and flowback waters As is commonly known, hydraulic fracturing has forced operators to deal with enormous volumes of water. Millions of gallons of water are necessary to frac the well and, once flowing, the well yields millions more gallons of produced water from the reservoir – briny water that is neither potable nor suitable for fracturing wells without treating it first.. The long-time practice of discarding produced and flowback waters in saltwater disposal (SWD) wells is rapidly losing its appeal. The reasons are numerous: inadequate pipeline infrastructure to transfer the water offsite; the high cost and nuisance of trucking the water offsite; the dwindling capacity of SWD wells; ever more stringent regulations and permitting of SWD wells; and mounting environmental and seismic concerns over SWD wells being raised by a growing number of communities and local governments. The cost/benefit ratio of recycling produced and flowback waters has also become significant. Rystad Energy reports that in the Permian Basin, disposal costs currently range between US$0.35 and US$0.75/bbl, whereas recycling costs range mostly between US$0.20 and US$0.30/bbl.2 Moreover, given the freshwater scarcity in the arid Permian and drought-prone western states of the US more generally, it is reasonable to expect the cost of sourcing freshwater in these regions to rise significantly in the years ahead. With regard to ESG concerns, recycling produced and flowback waters is simply the more sustainable practice. Rystad notes in the same report cited above that produced water recycling currently accounts for approximately 40% of frac water demand in the Permian, and that percentage is expected to increase to approximately 45% by 2026.2 Now that water recycling is proving to be effective and cost-efficient in many operations across the US, the point has been reached where the technology has simply become smart business practice and even integral to many operations, especially in water-scarce regions such as the Permian. In other words, the industry has turned a corner. Yet, as advantageous as water recycling is, it is even more efficient and cost-effective through automation.
machine learning and optimisation, as well as the capability to generate reports on a wide range of metrics and processes. Adding automation to water recycling and overall water management is now the latest trend for further enhancing efficiencies. A task that is easily automated, for example, is controlling and monitoring pumps and water tank levels to prevent spills and ensure adequate volumes of treated water are supplied in a timely manner for each frac stage. Other tasks that can be automated include chemical treatment, blending and water distribution. In fact, setting up a fully integrated automated water management system is better than having one or two discrete components that are automated. In the case of the former, everything that can be automated is automated, with the various components fine-tuned to operate in unison for maximum efficiency and accuracy. In terms of design, a fully integrated automated water management system begins with sensors and programmable logic controllers (PLCs) mounted on the tanks, pumps, chemical treatment system, blending controller and distribution manifold. The sensors transmit operational data via cellular or satellite communication to the computing cloud. The PLCs ensure equipment continues to operate properly should connectivity be interrupted. Each piece of automated equipment will have a digital twin displayed on a computerised dashboard, in the office or control centre, or even on mobile devices such as smartphones and tablets, which provide access from practically any location. The dashboard enables service technicians and client representatives to view the full spectrum of metrics, e.g. tank levels, treatment volumes, blend composition, pump speed, pump-engine fuel consumption and captured sand volumes. Such accurate, real-time data enables those monitoring operations to not only generate reporting trends, but also tweak parameters to optimise the efficiency of each component as well as overall operations.
The ESG benefits of automated water management Taking the three areas of ESG as an organising principle, this section will examine the many benefits of an integrated automated water management system.
Automating water management Automation has already proved beneficial in other oil and gas applications – such as pipe handling, managed pressure drilling and subsea work – and it is now integral to completions. In this regard, ‘automation’ means a lot more than something like a vehicle tyre triggering an automated carwash. It entails not only remote, hands-off activities, but also real-time computerised monitoring, diagnostics,
Environmental First, a produced and flowback water recycling programme means a lot less freshwater is needed during hydraulic fracturing operations, and it can basically eliminate wastewater disposal. Both improvements greatly lessen truck traffic on roads, thereby reducing exhaust and noise pollution – a noteworthy environmental benefit. Second, an integrated automated water management system can reduce the number of personnel needed at the wellsite, which also cuts vehicular traffic to and from the site and reduces the risk of human error that may cause spills.
Figure 1. TETRA Technologies’ integrated automated water management system.
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The social aspects mirror the environmental ones to some degree. Local communities certainly welcome less noise and exhaust pollution from trucks, as well as less seismic activity associated with SWD wells. Yet they can continue to benefit from the tax revenue and economic activity of industry operations and personnel. In terms of the big picture, more sustainable and cleaner oil and gas development means the sector can continue to meet the growing energy demand of communities and regions.
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Corporate governance In terms of corporate governance, the benefits of water recycling and an integrated automated water management system have already been more or less outlined above. Recycling produced and flowback waters is a sustainable business practice that puts a company in good standing with the public, regulators, shareholders and investors. Automation reduces headcount at the wellsite, which reduces not only training time and costs but also reduces the exposure of personnel to risk, ultimately making operations safer for everyone involved. Automation is also, by definition, more efficient, assuming the system is properly integrated and not unnecessarily complicated. Finally, automated water recycling can improve profits and return on investment because it is more cost-efficient. With the cost of recycling water now trending below that of disposal, it simply makes good business sense to do it.
Conclusion While some might view ESG concerns as merely the latest craze, a popular fad destined to eventually fade away like the pet rock and peak oil, it is better to recognise ESG concerns as fast evolving factors that will become just as integral as safety and ethical business practices. Obviously, only time will tell, but the ESG trend does in fact align with the much longer historical trajectory of seeking more sustainable ways of living, working, maintaining civilisation and safeguarding the environment. Sustainability might be one of today’s hot buzzwords, but upon consideration it becomes clear that the practice lies at the very heart of life itself. Knowingly or not, a squirrel both forages and plants, ensuring the continued cultivation of more trees, just as humankind has learned not to over-cultivate soil so as to avoid massive crop failure and famine – think of the Irish Potato Famine in the mid-1800s.
Humanity’s relationship with water must be sustainable too, as it is something of a commodity; although not traded like gold, silver and sugar on the commodities market, it is in so many ways far more valuable. Most people take the availability of clean water for granted – it usually takes severe drought, contamination or the catastrophic failure of plumbing to remind us (painfully) of its value. Nations have gone to war over water, California experienced its notorious water wars in the early 1900s (which figure prominently in the movie ‘Chinatown’), and more recently one can read scores of articles about “the coming water wars.”3 Hydraulic fracturing may seem like the opposite problem – too much water! – but it is really just the flip side of the same issue: finding ways to manage and use water in sustainable ways that are good for the environment, civilisation and business. Unlike oil, which might be continuously created deep within our planet,4 water is probably a finite resource. Recycling produced and flowback waters really is the answer to the question of sustainability, because doing so benefits the environment and every stakeholder in the equation – communities, land owners, regulators, companies, workers, shareholders and investors.
JESSOP, S., and HOWCROFT, E., ‘Sustainable fund assets hit record $1.7 trln in 2020: Morningstar’, Reuters (28 January 2021), https://www.reuters.com/article/ us-global-funds-sustainable-idUSKBN29X2NM Rystad Energy, ‘Water Management Report – 3Q 2021’, Shale Intelligence (1 July 2021), pp. 13 – 15. See PARKER, L., ‘What You Need to Know About the World’s Water Wars’, National Geographic (14 July 2016), and DARLING, D., ‘The Coming Wars over Water?’, The National Interest (14 April 2019). See RINGLE, K., ‘A Scientific Heretic Delves Beneath the Surface’, The Washington Post (1 November 1999), an article about physicist and cosmologist Thomas Gold, who argued “the long-held assumption that oil comes from millennial composting of dinosaurs and ancient swamps has always been dubious,” and instead proposed an alternative theory in his book The Deep Hot Biosphere: The Myth of Fossil Fuels (2001).
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GLOBAL WAT ER PRODUCTiON Kelsey Gonzalez, Valiant Artificial Lift Solutions, USA, outlines how an increasing demand in oil will affect global water production, and how horizontal pumping systems can be used to address this.
s the world emerges from the economic disruption of 2020, the International Energy Agency (IEA) predicts that global oil demand will sharply rebound in 2021 and rise to 104.1 million bpd by 2026, 4.4 million bpd above pre-pandemic levels.1 Driven primarily by worldwide economic expansion, and underpinned by emerging and developing economies with rising populations and incomes, meeting this demand will require world oil production to grow by 10.2 million bpd. For every barrel of oil recovered, 5.7 bbl of water are produced on average, which raises an issue for producers: how can all this water be handled sustainably and cost-effectively?2 Based on recent global estimates, the oil and gas industry produces more than 400 million bpd of water, assuming an 85% water cut. However, as conventional fields mature and global production increases, the total volume of
produced water will also rise, resulting in even greater demand for water infrastructure. Currently, approximately 75% of produced water is reinjected for either enhanced oil recovery or disposal, as this is the preferred and lower-cost method for operators compared to recycling.3 Recycling or re-use of produced water requires various technologies and access to facilities to perform the treatment processes necessary to remove solids, organic compounds, heavy metals and other impurities. Moreover, increasing environmental pressures over the last two decades have forced greater regulation on the discharge of produced water, thus increasing the costs associated with treatment in order to meet quality thresholds for releasing produced water back into the environment.4 These trends point to injection continuing to be the primary method for managing produced water among oil and gas producers.
Current practices for produced water disposal Injection facilities often require pumps capable of producing high pressures of up to 2000 psi while simultaneously handling increasing fluid volumes. For some national oil companies (NOCs), water production across multiple fields can exceed 16 million bpd, requiring robust infrastructure to ensure efficient water handling and prevent bottlenecks.5 Ultimately, selecting the right pump technology and configuration depends on the operators’ water volumes, access to third-party disposal or treatment services, capital constraints and operational targets, as well as the quality/composition of their produced water and local regulations. One technology trend among water handlers is the application of horizontally mounted multi-stage centrifugal pumping systems (HPS) for these types of large-scale water injection facilities. While there are thousands of HPS units in operation around the world, few are designed to produce more than 8000 – 10 000 bpd of fluid.6 For a large NOC, this means accommodating potentially hundreds of units in order to inject the majority of their produced water, which presents significant challenges with regards to maintenance, environmental risk and efficiency losses. The more units in operation, the greater frequency and cost for service, maintenance and repairs, as well as larger surface footprint and higher potential for leaks or spills. Furthermore, dividing the volume requirements across several units in parallel is not a perfect solution, since each unit will perform at varying efficiencies
and compete for space in the landing zone. This can result in systems performing 20 – 33% below the designed production rates.7 In this type of configuration, the back pressure and motor frequency must be controlled for each individual pump in order to optimise the site as a whole, which may require highly experienced technical support to properly calibrate. This disconnect between the sheer volume of produced water from oil and gas operations in the world and the limited capabilities of the current system configurations highlights both the technological and economic hurdles operators must address in their water management practices.
Technological and economic limitations HPS units are modular and can easily be configured with pumps of varying sizes capable of producing volumes of 100 000 bpd or higher; the pump is not the limiting factor however. When considering the forces that are exerted on the system during operation at high production rates through the pump, the task of effectively absorbing thrust load and preventing damage to the motor becomes much more difficult to manage. Consequently, heavy-duty systems come at a cost. Large pumps require thrust chambers with higher thrust limits and motors with more horsepower, which may require higher-spec controllers and instrumentation. This additional upfront cost may be the reason that more of these units are not in operation. Luckily, advancements in thrust chamber technology, coupled with an improving price environment, are causing some operators to revisit the viability of systems designed to produce 50 000 bpd of fluid or higher, and it is horizontal pump manufacturers such as Valiant that are helping to make it possible. In fact, the industry is pushing to develop technology that can produce even higher volumes in a single unit. The primary drivers behind this push for innovation are goals to reduce operating expenses (OPEX) while addressing produced water management in a safe and sustainable manner.
Lowering OPEX One advantage of larger HPS units is the consolidation of horsepower. For example, by replacing ten 5000 bpd pumps with one 50 000 bpd pump, a producer can reduce the required horsepower per barrel of fluid produced by 95%, thus improving site efficiency via lower power costs relative to production volume.
Figure 1. Valiant heavy-duty horizontal pumping systems producing
50 000 bpd
= 0.6 hp/bpd
= 0.03 hp/bpd
= 0.06 x 10
approximately 69 000 bpd of water.
Additionally, producers might reconsider the lifetime operational costs to maintain a fleet of smaller pumps compared to a smaller number of heavy-duty systems. A typical HPS should be monitored and serviced quarterly by a trained technician to check pump alignment, replace thrust chamber lubricant, take vibration readings and conduct any additional maintenance to keep the system running efficiently. Because the cost of labour, consumables and replacement parts multiplies with each additional unit on location, operators can significantly reduce their service costs by implementing fewer pumps with higher flow rates in their facilities.
Figure 2. V30 thrust chamber retrofit at water injection facility.
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Environmental risk associated with water management can be measured by several factors, including carbon emissions and the incidence of spills or leaks. When fewer horizontal pumps are installed on location, operators can minimise emissions associated with trucking and power generation, as well as lower their risk for produced water spills. Produced water
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may contain dissolved solids, heavy metals and naturally occurring radioactive material; spills therefore pose a significant environmental concern, especially where there is a high potential for contamination of groundwater reservoirs and nearby water sources. If leaks are detected at a produced water injection site, it will be much easier to contain where fewer pumps are present. That being said, it is worth noting that many operators prefer to have spare pumps on location in case a unit must be shut down. Therefore, the application of larger horizontal pumping units should be considered at facilities where there is significant opportunity for consolidation of water production volumes without reducing the facility to a single unit. As the industry begins to gain momentum and water pressures mount, new infrastructure is being implemented, but existing water infrastructure is also being restored for greater capacity utilisation. Oil producers with ‘legacy equipment’ need compatible replacement parts, but market rebalancing and service droughts have disrupted the supply chain, making it difficult for producers to recommission existing assets. To fill this market gap, Valiant has partnered with independent and national water handlers to provide turnkey ‘retrofit’ solutions for their HPS units. In addition to servicing pumps, motors, seals and supports, the company offers a complete kit for thrust chamber maintenance and replacements. Starting with the V7 – which is rated to a thrust limit of 7000 lbs – to the V30, rated for 30 000 lbs, Valiant has kept over 100 HPS units in operation in the Western hemisphere by providing thrust chamber retrofits using these proprietary designs.
by Spears & Associates, what they refer to as ‘multinational’ oil producers likely face even greater scrutiny over environmental sustainability than NOCs as a result of having more diversified stakeholders and reporting to multiple regulators.8 To reduce global emissions while securing reliable, efficient energy for the future, oil and gas must continue to be part of the energy mix. However, water scarcity and the preservation of natural water sources has become a poignant issue that has to be addressed at the field level. Spills, contamination and desiccation can have irreversible consequences on the environment. Reducing the risk of these incidents occurring in the first place should therefore be the utmost priority. By investing in new technologies and implementing cleaner and more sustainable water management practices, water producers can help minimise the environmental footprint of their operations and eliminate production bottlenecks for more efficient energy infrastructure.
As international trade and travel improves in the post-pandemic world, the oil and gas industry is expected to rebound relatively quickly, which means global water management infrastructure must catch up to operators’ production plans. As discussed in the June Drilling & Production Outlook
6. 7. 8.
References 1. 2.
International Energy Agency, ‘Market Report: Oil 2021’ (March 2021), https:// www.iea.org/topics/oil-market-report OLAJIRE, A., ‘Recent advances on the treatment technology of oil and gas produced water for sustainable energy industry-mechanistic aspects and process chemistry perspectives’, Chemical Engineering Journal Advances, Vol. 4 (15 December 2020), https://doi.org/10.1016/j.ceja.2020.100049 ECHCHELH, A., HESS, T., and SAKRABAN, R., ‘Reusing oil and gas produced water for irrigation of food crops in drylands’, Agricultural Water Management, Vol. 206 (30 July 2018), pp. 124 – 134, https://doi.org/10.1016/j. agwat.2018.05.006. DE FREITAS, A. L., and MENDES, L. C., ‘Brazilian Regulatory Framework Concerning Produced Water Final Disposal’, paper presented at the SPE International Conference on Health, Safety and Environment in Oil and Gas Exploration and Production, Rio de Janeiro, Brazil (April 2010), https://doi. org/10.2118/126974-MS EDGAR, Securities and Exchange Commission, ‘Ecopetrol S.A. Form 20-F for Fiscal Year Ended December 31, 2019’ (2020), https://www.sec.gov/Archives/ edgar/data/1444406/000110465920041416/tm206789d1_20f.htm Interview with service provider, (May 2021). Interview with HPS distributor, (June 2021). Spears & Associates, ‘Drilling & Production Outlook by Spears & Associates’ (June 2021), https://www.youtube.com/watch?v=K8ZcQnrf-84
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LE SSON S Pavel Khudorozhkov, Oleg Sychov and Dmitry Dolganov, AKROS LLC, Russia, and Valentin Tarsky and Ruslan Klishch, Sakhalin Energy Investment Co. Ltd., Russia, consider the findings, issues and lessons learned from the joint re-injection of drill cuttings and produced water into a low permeable formation offshore Sakhalin Island, Russia.
roduced water disposal is a very common problem on offshore platforms. Thousands of cubic metres of water are recovered daily with oil from producing wells and need to be safely disposed of in compliance with regulations. Subsurface injection is one of the effective methods for getting rid of large water volumes in an environmentally and economically sustainable manner. The presence of a cuttings re-injection (CRI)
system on a platform enables the combined disposal of produced water and drilling waste into the well, and reduces costs more than other alternative options. CRI is a method of disposing drilling waste into subsurface formations with downhole injection pressures above the minimum stress values. Injection at high pressures results in hydraulic fracturing of the formations and waste deposition in the developed fractured network.
Figure 1. Disposal sandstone layers correlation.
Figure 2. Fluids processing and water injection scheme.
Figure 3. Fracture close and pore pressure dynamics.
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The Sakhalin offshore CRI well, located in the far east of Russia, was used for produced water re-injection (PWRI) during the waterflood system reconstruction period, and has been used afterwards as a back-up for the other existing CRI well. The well is completed in two sandstone layers (Figure 1). Both layers are initially water-saturated. The layers are characterised by low permeability but are well correlated within the field. The total thickness of the upper injection target layer varies from between 15 to 30 m. The thickness of the lower layer is between approximately 5 to 10 m. The layers were studied for the purposes of CRI and were found to be suitable for the disposal of drilling waste. More than 100 000 m3 of waste was injected into the well over a period of 7 years. The disposed volumes included drilling waste (e.g. cuttings, waste mud and completion fluids) as well as a large percentage of produced water. The proportion of produced water in the injected waste reached 90% in some early periods of the well’s life. The produced water injections were characterised by intensive injection pressure growth. In total, more than 26 000 m3 of produced water was disposed of. Water that arrives with hydrocarbons from the production wells undergoes treatment before being disposed of through injection wells in the subsurface formation (Figure 2). The water that is separated from the oil goes through several stages of desanding and deoiling. According to laboratory reports performed during injection life, the processed water contains 0.2 – 1.65% of hydrocarbon by volume. The presence of oil in the injected fluid resulted in a two-phase liquid flow in water-bearing sandstones, which reduced water relative and total formation permeability. The disposal sandstone layers were initially water-saturated and could be characterised as water-wet. In this case, the oil invasion process is described as a drainage or wetting phase (water) displacement with a non-wetting phase (oil). Drainage results in the blockage of the largest pores with a non-wetting phase that intensely reduces formation permeability. In low-permeability rock, water as a wetting phase is displaced and trapped in the smallest pores, becoming non-mobile due to the capillary forces. In the case of two-phase filtration, fluids become mobile only when their saturation exceeds a level known as ‘critical saturation’. In the described case, the injected oil did not reach its critical saturation in the pore space and therefore remains immobile in the system. This assessment is based on the relatively low (compared to pore volume) injected volume of oil. Even if at some point oil saturation exceeded its critical value in any region close to the well, oil was displaced further into the water-saturated zone, becoming immobile again. This process can last continuously, resulting in the extension of the deteriorated zone.
The period of intensive produced water injection was and σ2 corresponds to the overburden pressure. In CRI the characterised by a rapid pressure increase. The transient stress difference between σ2 and σ3 decreases, due to the pressure analysis revealed a fast growth in the fracture closure waste accumulation in created fractures causing rock elastic pressure during the produced water injection (Figure 3). The deformation. A decrease in the difference between the stresses increase in closure pressure was the main factor that influenced diminishes the minimum Pnet value required for the fissures opening, consequently stimulating the fracture network injection pressures. The cuttings slurry disposal was not development. intensive during that time and should not be the main reason of The hydraulic fracture development during the injection can the minimum stress growth. be described using the log-log Nolte-Smith plot of the fracture The fracture post-closure transient pressure analysis, using net pressure versus time. The common injection pressure the Horner plot, was carried out for the cases representing different total injected waste volumes. The analysis was focused on the pore pressure and transmissibility of the disposal layers, in order to identify the reason for the closure pressure increase (Figure 4). A reduction in transmissibility was expected with the total injected volume increase driven by growing oil invasion. The Horner plot pressure lines, corresponding to the radial flow extrapolation to the pressure axis, indicated pore pressure growth with injected volumes. However, a reduction in transmissibility was not observed during the period of the most intensive produced water disposal (between 20 000 and 40 000 m3 of the total waste injected volume). The slopes of the pressure extrapolation lines did not show any stable steepness surge with the higher disposed volumes. The CRI disposal domain can be described as a complex fractured system. It may include multiple Figure 4. Post-closure pressure analysis. hydraulic fractures and a network of natural fractures opened under high pressure. The natural fractures (fissures) opening criteria was described by Nolte and Smith.1 The critical fracture net pressure for the fissure opening can be expressed as: σ
H,max –σh,min 1–2υ
where Pnet is the hydraulic fracture net pressure, σH is the max – maximum horizontal stress, σh is the min – minimum horizontal stress and υ is Poisson’s ratio. The formula variables are given for the normal tectonic environments, where σH , max corresponds to σ2 (or the intermediate principal stress), and σh , min corresponds to σ3, or the minimum principal stress. The Sakhalin offshore well is characterised by a strike-slip fault regime where σ3 corresponds to the minimum horizontal stress
Figure 5. Injection pressure analysis.
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pattern for the studied well is shown in Figure 5. The fracture propagation is characterised by the pressure curve slopes on the Nolte-Smith plot. The injection case demonstrates the pressure slopes mostly between 0 and 0.2 that correspond to Types III and IV of fracture propagation, according to the Nolte-Smith plot. Type III relates to the stress-controlled fissure opening, while Type IV shows the fissure expansion. Similar injection pressure patterns can be observed in most of the injection episodes. The natural fissure opening is also stimulated by the local pore pressure growth over the injected volume. The current pore pressure around the CRI well is almost twice as high as the initial value. The fissures opening at high injection and pore pressures could compensate the major matrix transmissibility damage due to the oil invasion, minimising the influence of the matrix permeability loss. Injecting at pressures above fracturing ones (with open fractures and fissures) stimulates well injectivity. The shut-in pressure decline rate is initially fast after the pump is stopped, but it slows down significantly when pressure falls below the fissure closure pressure. In classic CRI into a permeable formation, the solid phase is accumulated in the fractures while fluid filtrates into the porous media. The absence of matrix permeability and injection with pressures above the minimum stress results in both solids and liquid accumulation, generally in the created fracture network. The simultaneous fluid and solids accumulation in fractures, alongside the absence of fluid filtration, results in excessive rock elastic deformation, causing a fast stress increase. The authors suppose that once oil is trapped in small fissures it becomes
non-mobile and sealed from the rest of the formation; otherwise the fracture closure pressure increasing faster than the pore pressure cannot be explained. The closure pressure increase was disproportionally more rapid compared to the pore pressure growth during the periods of produced water injection (Figure 3). The formation stress growth during injections of solids-free fluids – such as produced water – should correlate with the pore pressure; the faster stress increase can only be explained by additional rock deformation and injected material accumulation inside the created fractures.
Conclusion The described case demonstrates the importance of careful selection of subsurface reservoirs (domain) for the disposal of large volumes of produced water. The potential oil content can significantly complicate the work and limit the operation time of the disposal layers and the well. Higher permeability formations are less sensitive to oil contamination. The increased number of larger communicating pores will reduce the two-phase filtration capillary effects, helping to avoid a catastrophic decrease in matrix permeability. It is important to note that there is only a small choice or even an absence of effective methods of overcoming the permeability loss. A large volume of deteriorated rock may need to be treated with a volume of chemicals comparable to the injected amount of waste, which is not economical.
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ECONOMIDES, M.J., and NOLTE, K.G., Reservoir Stimulation, 3rd edition (2000), pp. 9 –23.
MASTERING WELL PLACEMENT THROUGH
LEARNING Vidyasagar Ananthan, Beyond Limits, USA, explores how the emerging field of reinforcement learning can help to optimise well placement and field planning in the upstream industry.
ppraising the preservation of hydrocarbons within discovered fields is a critical aspect during exploration. This involves detailed seismic surveys, geostatistical analyses and subsequent high-resolution simulations involving geological models or digital twins representing the natural subsurface strata. In order to understand the practical production limit of a field, it
is necessary to find the best possible drilling locations, trajectories and control strategies given practical constraints – constituting the field planning process. Optimal placement and control of wells within such a greenfield development is a sequential decision-making problem of spatiotemporal nature. Deep reinforcement learning (DRL) has excelled in recent years at solving such sequential decision-making problems in a variety of scenarios, including board games and protein folding.1,2 However, within the upstream energy industry the application of this novel technology to achieve tangible breakthroughs has been relatively limited, compared to conventional techniques such as brute-force searches, genetic algorithms, gradient-based optimisation and particle swarm methods.
determining infill vertical well locations and using a recurrent neural network in place of physics-based reservoir simulations.6 Maiorov et al. have utilised the AlphaZero algorithm combining model-based RL with a Monte Carlo tree search Figure 1. A global static optimisation problem spanning n sequential states (left) is recast into a recurrent form methodology to place wells whereby each state is influenced by, and results in, other unique states (right). within an irregular grid.7 Yingwei et al. have used RL to trace individual well trajectories by considering directional drilling as a sequential decision-making process.8 The technology presented in the subsequent section expands on these works by considering a model-free DRL strategy for dynamic optimisation of multiple curved well trajectories within a greenfield development. To ensure a fair quantitative benchmark with previous works, the DRL framework is applied to the same waterflooding example of the Egg model.4 The benefits of using DRL frameworks for optimal well placement and trajectory design are presented in detail. Transfer learning, which allows for the neural network Figure 2. The RL agent, constituted of multiple neural networks, interacts dynamically surrogates embedded within the RL framework to be with a simulated reservoir environment as part of the DRL framework. extracted and used independently, is further discussed in subsequent sections.
Methodology DRL leans heavily on the concepts of dynamic programming, within which deep neural network surrogates are utilised, for example, to predict actions and estimate their value in achieving a desired target. As depicted in Figure 1, a global optimisation problem of spatial and time-varying character, spanning a number of states, is decomposed into recurrent sub-problems, which are by nature more easily solved. In order to reformulate global optimisation problems into this form, they need to satisfy the Markovian assumptions of history-independence and determinism – and are subsequently termed Markov decision processes (MDPs). Once expressed in recurrent form, Bellman equations are used to solve for the optimal actions at each state constituting a sequence or plan of actions. While this applies to discrete decision-making processes, Figure 3. Diagrammatic representation of DRL framework, ingesting reservoir data the same methodology for a continuous sequence leads and configuration parameters to produce an optimal field plan to maximise NPV, to the Hamilton-Jacobi-Bellman partial differential together with trained weights for actor and critic neural networks. equations. Applied to the field planning example, the solution to the Bellman equations constitutes a Past efforts include the work of Hourfar et al., which describes RL agent that interacts dynamically with a simulated reservoir a reinforcement learning (RL) approach to control water injection environment, as depicted in Figure 2. rates of fixed wells for a waterflooding problem.3 The geological The RL agent provides information to the environment about model considered in this work for the waterflooding scenario predicted actions, or well locations and trajectories, and receives is an industrial benchmark known as the ‘Egg’ model, first information from the environment about states, which describe described by Jansen et al.4 Miftakhov et al. have used RL for 2D the saturation, pressure and other primary variables describing models to learn optimal rate control for fixed wells purely from the system. Together with this, the rewards of the predicted pixel saturation and pressure data.5 actions – namely the net present value (NPV) associated with More recently, De Paola et al. have performed vertical cumulative hydrocarbon production – are transferred back from well optimisation by considering the field development the simulation environment to the RL agent. The simulation strategy as a partially observable Markov decision process for environment used in this work is a high-fidelity physics-based
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reservoir simulator; however, the same methodology can be applied to a data-driven digital twin or neural network proxy as the forward model. The particular flavour of RL techniques adopted within this framework is a variant of the soft-actor-critic (SAC) algorithm.9 This is a model-free approach, and hence information about the specific reservoir model or simulation strategy is not embedded within the RL agent. This is crucial for the generalisability of the application across different reservoir models, with varying complexity of physics incorporated within the governing equations. Additionally, the technique itself exhibits stochasticity and entropy-regularisation, which admit new insights into the problem since the solutions avoid local optima in the NPV topological landscape. Practically, this implies that predicted well locations will not be locked within regions where NPV does not change with well trajectories or initial drilling points. Finally, the SAC algorithm is conservative in determining the value of actions by considering the minimum of multiple Q-functions (or action-value approximators). This ensures that the NPV of well locations is not overestimated at an intermediate stage within the DRL framework, resulting in improved optimal predictions.
The implementation of the DRL framework for field planning is illustrated in Figure 3. The reservoir information, consisting of grid data, porosity and permeability fields, together with the initial and boundary conditions, are supplied to the DRL algorithms. Parameters including the lifetime of the reservoir (or time of simulation), number of wells and heuristics for RL are used to configure the computational run. Within the SAC algorithm, two independent convolutional neural networks (CNNs) are used as the action-predictor (or actor) and the value estimator (or critic). The initialisation phase of the RL cycle consists of generating random permissible actions, which spawn a number of independent physics-based reservoir simulations. Once the reward and altered state data is available, this is used to train both the actor and critic neural networks on-the-fly, which then begin the learning phase of the RL cycle. A replay memory buffer stores a number of actions, states and associated rewards that are sampled randomly for training, and the stochastic noise added to actor predictions decays with the progress of RL. The best action, together with the associated NPV reward, is obtained at the end of a specified number of iterations or upon convergence of the algorithm. As an additional output, the trained actor neural network (which takes states and provides actions) and critic neural network (which evaluates the value of actions given state-action pairs) are also obtained and can be used independently of the DRL framework.
Results and discussion
Figure 4. Results of the benchmarking exercise plotting NPV solution values against the number of forward actions or well locations sampled by the RL agent, indicating convergence to a peak of US$51 million.
Figure 5. Transfer learning through the actor neural network, (a) allowing pre-training for convergence acceleration in different scenarios, (b) interpolating from coarse to fine grids, (c) from simple physics to more detailed full-physics simulators and (d) from geometrically simple models to complex realistic subsurface reservoirs incorporating large grid sizes and non-trivial mesh connectivity.
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The DRL framework has been applied to the Egg model, which, as previously mentioned, is an industrial benchmark for field planning.4 The waterflooding scenario was used with a variable number of hydrocarbon producer and water injector wells. Whilst the framework is designed to find optimal splines for the well trajectories, for this benchmarking only vertical wells were used. A constraint was placed on the total number of wells, including producers and injectors. The simulations and RL algorithms were run simultaneously and asynchronously on an AWS p4d instance over the course of 36 hours, utilising the power of GPUs for massively parallel processing and training of the actor and critic neural networks. The complexity of these CNNs (layers, kernel size) was tuned to capture the intricate physics of the dynamic reservoir simulations. The numerical results of the NPV optimisation obtained from the DRL framework are shown in Figure 4. The NPVs obtained through the simulation environment per action-state pair, during the lifetime of the reservoir, are plotted against the number of actions sampled. During the initialisation phase, the brute-force random search yields a range of low-NPV solutions, and after approximately 3000 actions sampled the DRL algorithm oscillates around an intermediate peak of approximately US$25 million. As the number of actions sampled increases, there is a transition to the convergent phase, settling at approximately US$40 million after 30 000 actions sampled. Eventually, a peak NPV of US$51 million is found after approximately 108 000 iterations or actions sampled, corresponding to a 4 producer, 1 injector configuration.
It is interesting to note that the graph exhibits oscillatory character until the noise fully decays; the decay parameter is a heuristic which is tuned to avoid premature convergence to a suboptimal well placement plan. Occasional solutions are found to have negative NPVs, whereby the injection costs outweigh the temporally discounted returns from cumulative production – in such cases, the algorithm autonomously learns to avoid such field plans. A further outcome of the SAC framework includes the two artificial neural networks representing the actor and critic, which are trained on-the-fly during the RL cycle. These networks can be used independently or as initial weights for subsequent runs of DRL. Figure 5 depicts scenarios where the actor-network, as an example, could be used, including: Addition of extra layers to pre-trained networks to accelerate convergence and studying the relationship between geostatistical properties and optimal well locations for artificially generated states. Interpolating from DRL cycles run on coarse meshes to finer meshes, improving accuracy (Figure 5b). Training on reduced reservoir physics models, for instance the black-oil formulation, to a compositional formulation relying on equations of state (Figure 5c). Selectively training layers in order to go from a simple model (e.g. the Egg reservoir) to more complex models (e.g. the Norne reservoir), as shown in Figure 5d.
Ì Ì Ì
The DRL framework detailed in this work admits algorithmic and computational performance improvements for further generalisation. Beyond field planning, the same techniques are applicable to improving geological carbon sequestration strategies and other green technologies.
DRL has proven to be an effective strategy for field planning, as demonstrated in this work, with strong potential for tangible breakthroughs in the upstream oil and gas industry. As the industry moves towards digital transformations, novel artificial intelligence/machine learning technologies – such as those presented here – should see significant advancements.
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SILVER, D., HUBERT, T., SCHRITTWIESER, J., ANTONOGLOU, I., LAI, M., GUEZ, A., and HASSABIS, D., ‘A general reinforcement learning algorithm that masters chess, shogi, and Go through self-play’, Science, Vol. 362, No. 6419 (2018), pp. 1140 – 1144. SENIOR, A.W., EVANS, R., JUMPER, J. et al, ‘Improved protein structure prediction using potentials from deep learning’, Nature 577 (2020), pp. 706 – 710. HOURFAR, F., BIDGOLY, H. J., MOSHIRI, B., SALAHSHOOR, K., and ELKAMEL, A., ‘A reinforcement learning approach for waterflooding optimization in petroleum reservoirs’, Engineering Applications of Artificial Intelligence, No. 77 (2019), pp. 98 – 116. JANSEN, J. D., FONSECA, R. M., KAHROBAEI, S., SIRAJ, M. M., VAN ESSEN, G. M., and VAN DEN HOF, P. M. J., ‘The egg model–a geological ensemble for reservoir simulation’, Geoscience Data Journal, Vol. 1, No. 2 (2014), pp. 192 –195. MIFTAKHOV, R., AL-OASIM, A., and EFREMOV, I., ‘Deep reinforcement learning: Reservoir optimization from pixels’, Presented at the International Petroleum Technology Conference, (January 2020), OnePetro, https://onepetro.org/IPTCONF/proceedings-abstract/20IPTC/2-20IPTC/ D021S052R002/154747 DE PAOLA, G., IBANEZ-LLANO, C., RIOS, J., and Kollias, G., ‘Reinforcement Learning For Field Development Policy Optimization’, paper presented at the SPE Annual Technical Conference and Exhibition (October 2020). MAIOROV, K. N., CHEBKASOV, D. S., ANTIPIN, D. V., VACHRUSHEVA, N. O., KARACHURIN, N. T., and LOZHKIN, A. G., ‘On the application of the Alpha Zero algorithm to optimize the placement of an irregular grid of production wells (Russian)’, Oil Industry Journal, Issue 3 2021 (March 2021), pp. 76 – 78. YU, Y., CHEN, W., LIU, O., CHAU, M., VESSELINOV, V., and MEEHAN, R., ‘Training an Automated Directional Drilling Agent with Deep Reinforcement Learning in a Simulated Environment’, paper presented at the SPE/IADC International Drilling Conference and Exhibition (March 2021). HAARNOIA, T., ZHOU, A., ABBEEL, P., and LEVINE, S., ‘Soft actor-critic: Offpolicy maximum entropy deep reinforcement learning with a stochastic actor’, paper presented at the 35th International Conference on Machine Learning (July 2018), pp. 1861 – 1870, Proceedings of Machine Learning Research.
STREAMLINING EXPLORATION S
eismic surveying is one of the first steps for exploring and developing an oilfield or natural gas deposit. By measuring the level of vibration throughout the subsurface, an accurate picture of the rock underground – and any liquid or gas deposits – can be generated and used to inform drilling locations. As operators seek to keep exploration costs from exceeding financial viability, seismic acquisition still presents a significant investment. In order to sustain the current scale of operations while also meeting internal targets for Scope 1 emissions reduction, scaling down the size and weight of seismic technology presents a significant opportunity for operators to streamline exploration without sacrificing data quality.
Current seismic equipment inflates exploration costs and emissions On average, for a 10 000-channel system, an operator can choose to purchase a cabled solution with receivers for US$350 – US$450 per channel, while newer, traditional wireless nodes are typically US$150 – US$350 per channel. Multiply this by the number of receivers needed to generate an accurate image of the subsurface, and this still only represents a fraction of the cost of seismic surveying. The logistics behind seismic surveying are a key driver of cost. Seismic cable solutions typically weigh between 15 – 20 kg per channel, while traditional wireless nodes on the market weigh between 650 g and 1.3 kg per unit. As such, in order to put thousands of nodes out in the field with traditional receiver equipment, multiple heavy-duty trucks are needed to transport equipment along with a large enough team to carry and lay out this equipment in the field, which introduces greater health, safety, security and environment (HSSE) exposure risks. Beyond the inflation of exploration costs, seismic acquisition often leads to significant environmental disruption. In addition to emissions from vehicles, forested locations are often partially or fully cleared to make way for teams, vehicles and seismic cabling. Streamlining seismic acquisition can therefore help operators reduce Scope 1 emissions and overall environmental impact, while also reducing costs.
Scaling down the size and weight of nodes STRYDE launched its node in 2019 with a focus on reducing the size, weight and cost, to enable high-density seismic surveying. The node weighs 150 g – over 10 times less than cabled receivers and over four times less than other nodes on the market.
Mike Popham, STRYDE, UK, discusses how scaling down the size and weight of seismic nodes can help streamline exploration.
Scaling down the size and weight of the receiver has a considerable impact on the number of vehicles and personnel needed for a project. For example, 5000 STRYDE nodes can be safely stored in a single pickup truck. On average, the number of vehicles for transporting not only equipment, but also team members, can be reduced by 80% through the use of these lightweight seismic nodes. In the final R&D phase demonstration of the company’s technology in the UAE, an average of 10 000 nodes were laid out and a further 10 000 nodes were retrieved every 6 hours by 36 people. Half a million node deployments were made in this survey, which took 53 days to complete over sand dunes and oilfield infrastructure.
Nimbler operations in rugged terrain Reducing the size and weight of not only seismic nodes, but also the supporting peripherals, allows for a safer, lower environmental footprint and lower cost operations even in difficult environments for exploration. STRYDE nodes are light enough for a single person to carry between up to 90 nodes, meaning a two-person crew can deploy and retrieve hundreds of receivers in a single shift. As such, lighter nodes can deliver
seismic even in circumstances where a smaller crew size operating on a faster schedule is necessary due to political, environmental or spatial requirements and limitations. The ability to transport seismic nodes on foot rather than via vehicles has enabled seismic surveying of rugged and forested environments without significant environmental impact. Rather then try and circumvent steep hills or rocky formations with the use of expensive, high-risk and emissions-intensive helicopters or extensive environmental clearing, the company’s partners were able to carry and place nodes on foot, weaving between boulders and forestry. Smaller, lighter nodes also enable operators to reduce the footprint and manpower associated with handling, storing and charging nodes. For example, the STRYDE Pro System, designed for clients requiring more than 150 000 nodes on crew, allows one person on shift to download and recharge 20 000 nodes per day inside a single 20 ft container. The company has also designed the node to withstand a variety of environments, from the taiga in Russia, to deserts in the Middle East, to the Rocky Mountains in Canada. The node is built to continuously record for at least 28 days in a temperature range of -40˚C to 70˚C. Once a node has been placed, it requires no further intervention until the time comes to collect it – minimising the need for personnel onsite.
Health and safety of crews
Figure 1. The STRYDE system reduces the need for receiver line clearing, including in dense forest.
Scaling down the size and weight of seismic nodes drives significant improvements in health and safety for operators and contractors. One of the most common causes of health and safety incidents during seismic acquisition are vehicle-related incidents. Lowering the number of vehicles and time spent onsite transporting seismic equipment can therefore substantially reduce this risk. Line clearing in forests also introduces significant HSE risks, but this process can be removed by scaling down the size and weight of nodes. Smaller crews also mean fewer people are exposed to potentially hazardous locations and situations. In areas with steep slopes and rocky terrain, limiting the number of people onsite reduces the risk of injury from falls on a per-project basis. When public health mandates restricted the number of onsite personnel due to COVID-19, the company was able to support operations via smaller, lighter node systems for crews that could consist of only two or three employees due to these requirements.
The benefits of streamlining exploration
Figure 2. The STRYDE Node is a small and light seismic receiver.
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The oil and gas industry faces the twin challenges of increasing calls for investment into environmental sustainability and the likelihood that oil prices will never recover to their heights of a decade ago. Streamlining processes throughout the supply chain can help companies deliver projects while lowering emissions and overall costs. The oil and gas sector is ready for another revolution in seismic technology: as the industry pivots towards lighter and smaller autonomous nodes, operators can reduce the number and size of vehicles needed to complete seismic surveying for a project.
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