MAGAZINE | SUMMER 2022
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Contents 03 Comment
Summer 2022 Volume 15 Number 02
32 Don’t Ditch The Data Danny Constantinis, EM&I Group, Malta, explains how data analysis and AI combined with RBI strategies and robotic data collection systems could become the future of asset integrity management in the oil and gas industry.
05 World news 10 Bouncing Back Prateek Pandey, Rystad Energy, Singapore, considers how upstream activity in Southeast Asia could be revived after the market shocks caused by the COVID-19 pandemic, and details the region’s production outlook and investment focuses.
16
A Long-Term Preservative For The Biocide Toolbox Jennifer Knopf and Dr. Ulf W. Naatz, Vink Chemicals, Germany, outline the importance of selecting the right biocide to help mitigate and control bio growth in subsurface, downhole, or topside oilfield operations.
21 Rising To The Challenge Roar Pedersen, Andreas Fliss, and Fernando Zapata Bermudez, Archer Oiltools, Norway, explain how the development of a packer, as part of the drilling BHA, could help overcome the challenges involved with drilling depleted reservoirs.
25 Improving Bit By Bit Dustin Lyles, Brandon Sheldon, and Casey Kitagawa, Taurex Drill Bits, USA, explain how the evolution towards digitalisation and analytical evaluation has impacted drill bit performance.
Don’t ditch the data D
ata analysis and artificial intelligence (AI) could be seen as the key to safe and efficient integrity management. Often when data is collected, a large proportion of it goes to waste, along with the costs and risks of gathering it. A reason for this is that the prescriptive regulations calling for the data represent a shotgun approach based on the lowest denominator in terms of asset condition; in other words, lots of data is gathered, and one or two useful pieces of information that confirm base compliance are found, meaning the rest is discarded. The second reason is that until analysis and AI became more widely recognised and understood, data had been seen as too difficult to analyse quickly or cost effectively. The third reason is that new, robotic, and remote inspection methods gather more data than ever, which could be perceived as overwhelming.
What is the oil and gas industry doing to remedy this? The JIP (Joint Industry Project) for HITS (Hull Inspection Techniques and Strategy) has stimulated thinking on
this topic due to the increasing applications of remote technologies that collect vast amounts of data for analysis, providing useful insights into asset condition and trends. There are a number of challenges regarding data and metadata. How should it be collected? How frequently? By what methods should data be collected? And how should it be managed and analysed? Many of these questions can be addressed through using a risk based integrity strategy rather than following prescriptive rules.
Risk based strategy
Risk based strategies for assuring equipment integrity are efficient because they target known critical areas. This makes RBI and remote inspection systems highly compatible, avoiding the gathering of unnecessary data. However, RBI does require knowledge of the equipment design, inspection, maintenance, and operating history.
Danny Constantinis, EM&I Group, Malta, explains how data analysis and AI combined with RBI strategies and robotic data collection systems could become the future of asset integrity management in the oil and gas industry.
How would an RBI approach work for a floating offshore asset such as an FPSO?
Rather than follow prescriptive class rules that require inspection data irrespective of the specific integrity risks of the structure, the RBI approach focuses on gathering data relevant to the structure in question. An RBI inspection plan and work pack will be developed by a group of people knowledgeable in the RBI process and experienced in the history and operation of the asset. The inspection plan identifies the ‘what, how, and when’ of the data gathering process, generally seeking to extend inspection intervals where appropriate. Often, the increased inspection intervals may be contingent on some form of confirmatory visual inspection, and this is where remote systems such as NoMan and UAV come into play.
What data needs to be collected and how?
In the case of structural integrity on an FPSO, visual inspection, distortion, thickness, and coating data may be collected, however
metadata such as the loading condition, ambient conditions, sea state etc., should also be considered. The collection of inspection data is a rapidly changing topic being discussed across the industry in JIPs such as HITS (Hull Inspection Techniques and Strategy). Key drivers include safety, cost, sustainability, and environmental aspects, and especially emissions reduction. Workers should not be put at risk through working at height, in confined spaces, or in dangerous environments such as working underwater to gather integrity information. It is often difficult to justify the benefit of inspections to protect life when there are fatalities involved in gathering the data to do so. Solutions to this dilemma include using robots and modern, data gathering technology such as remotely operated cameras and laser scanners to gather data. This type of solution goes a long way to resolving the second challenge of cost and operational efficiency. Making an environment safe for humans is much trickier than making it available for a robot.
32 |
29 Seeing Past Traditional Approaches Matt Rothnie, Vysus, UK, examines how rig selection for well decommissioning can be influenced by the development of a ‘fit for purpose’ well abandonment philosophy, alongside optimised unit selection.
| 33
36 When Man Meets Machine Philippe Herve, SparkCognition, USA, considers the uses of AI in the upstream oil and gas sector and discusses its role in performance optimisation.
39 To Flow Or Not To Flow Dr. Bruno Pinguet, TÜV SÜD National Engineering Laboratory, UK, outlines how uncertainty analysis can help determine the capabilities of flow measurement systems in meeting their required performance targets.
Front cover Vink Chemicals biocides: Microbial Control in Oilfield & Fuel Applications Oil producers must frequently deal with various types of microorganism during specific processes of oil production. Aerobic and anaerobic bacteria can be present in all water-containing fluids. Many studies have reported varied resistance levels to biocides referring to consortia enriched from produced water samples, indicating a specific response to each biocide. This translates into the need for various biocide chemistries or for applying the concept of combined treatments. Read Vink Chemicals’ article on P.16.
42 Go With The Flow
MAGAZINE | SUMMER 2022
Ken Feather, TGT Diagnostics, UAE, describes a new approach to flow diagnostics in horizontal wells.
46 Combatting Corrosion And Deposition Ana Ferrer, Ph.D. USA, and Brian Bennett, ChampionX, UK, discuss the importance of combatting iron sulfide deposits and scale in flowlines and water processing systems.
52 Ready For Lift-Off! Anil Wadhwa, Baker Hughes, USA, considers how digital technology could help offshore operators maximise artificial lift system performance.
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Guest Comment Contact us Patrick Long, Director in Opportune LLP’s Process & Technology practice Bitcoin mining & ESG: Why digital transformation can enhance visibility and transparency. Bitcoin mining has converged with the energy sector at a rapid pace, yielding an explosion of innovation in the name of ESG. Here is what it means for the oilfield going forward.
T
he past few months have seen headlines that reinforce creativity and innovation within the energy industry, all in the name of Environmental, Social, and Governance (ESG). First, there is Bitcoin. While it is not a new phenomenon, Bitcoin’s popularity is driven by a larger acceptance of cryptocurrency and that more companies are accepting it as a form of alternative currency in transactions. Bitcoin also has been driven by the outspoken voice of billionaire Elon Musk. However, mining Bitcoin requires using a lot of energy and the size and scale of mining operations have grown over the years. It is estimated that mining one Bitcoin transaction takes 1544 kWh to complete. That is equivalent to 53 days of average power for a US household. Supermajors like ExxonMobil have even entered the cryptocurrency mining trend with the expansion of an initial pilot to use flare gas at oil drilling sites globally to power servers and supercomputers, according to media reports. Second, the upstream drilling of crude oil produces an excess byproduct — natural gas — which is often flared or vented due to a lack of pipeline infrastructure. According to the US Energy Information Administration (EIA), the volume of natural gas vented and flared reached 1.48 Bcf/day in 2019, with 85% of those emissions coming from the Bakken play in North Dakota and the Permian Basin in West Texas. Flare gas is harmful to the environment since it is released into the atmosphere. For years, the energy industry has focused on flaring this byproduct since it was not economically feasible to store and ship it to a destination. The new and interesting juxtaposition is the intersection of using flare gas as a fuel to drive Bitcoin mining operations. Economics typically serves as a stimulus to jumpstart innovation. The ingenuity of the industry allows harmful waste (flare gas) to be recycled fuel for Bitcoin mining. According to Bloomberg, Exxon has expanded an initial pilot to use flare gas at oil drilling sites to power servers for mining Bitcoin. Fossil-based energy companies are getting positive headlines and credit in the eyes of consumers and investors for channeling the waste into something useful, or at least productive. According to Crusoe Energy Systems, one of the largest Bitcoin miners in the US, its process reduces CO2e emissions by 63% compared to regular flaring. With oil companies facing mounting pressure from governments and agencies to reduce their greenhouse gas (GHG) emissions, one could assume that it makes sense, both environmentally and economically, for an oil and gas producer to link up with a Bitcoin miner and supply it with stranded or otherwise flared natural gas to comply with ESG initiatives. But pilot projects performed in a vacuum cannot truly be gauged for effectiveness. The data gathered from the conversion of flare gas to fuel provides keen insight into managing this aspect of ESG. The valuable lesson here points to the adage, ‘if you can measure it, you can manage it.’ This is why integrating digital transformation technologies is critical within the upstream industry to measure gas flaring. While any number of measurement devices exist to measure gas flaring, the power comes in an integrated dashboard to show the offsetting benefit of fuel usage. Once baselines are taken and calculated, these offsets can then be calculated when the natural gas is recycled and used as fuel. It is this visibility and transparency that is so critical to helping investors and the public gain confidence in knowing how the opportunity of ESG is being addressed within the upstream oil and gas industry.
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Summer 2022 Oilfield Technology | 3
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World news Equinor makes new discovery near the Johan Castberg field in the Barents Sea Shortly after the Snøfonn North discovery near the Johan Castberg field in the Barents Sea, Equinor has made another oil and gas discovery in Skavl Stø, exploration well 7220/8-3. The well was drilled 5 km south-southeast of discovery well 7220/8-1 on the Johan Castberg field, 210 km northwest of Hammerfest. Equinor is the operator of production licence 532. The size of the discovery is preliminarily estimated at between 5 – 10 million recoverable boe. Together with the other licensees, Vår Energi and Petoro, Equinor will consider tying the discovery into the Johan Castberg field. “The drilling operation was safely and efficiently performed. The new discovery and information will be viewed in the light of other discoveries in the area, and together with our partners we will consider further development of the area,” says Kristin Westvik, Equinor’s Senior Vice President for exploration and production north. The news about the Snøfonn North oil discovery was published on 25 May this year, about one year after the Isflak discovery in the same area. Skavl Stø will be further matured together with Snøfonn North and the previous discoveries Skavl (2014) and Isflak (2021). The well was drilled by Transocean Enabler. Skavl Stø is the thirteenth exploration well in the Castberg licence. The production licence was awarded in the 20th licensing round in 2009.
Well-Safe Solutions to undertake Ithaca Energy North Sea well decommissioning Well-Safe Solutions has been contracted by Ithaca Energy to plug and abandon (P&A) six wells on the Anglia platform in the Southern North Sea, approximately 55 km from the UK mainland. The contract will see the Aberdeen-based well decommissioning specialists provide project management, well engineering and all managed delivery services for the project. The Well-Safe Protector harsh environment jack-up rig is nearing the end of extensive technical preparations and will mobilise to the field in late summer 2022. Matt Jenkins, Chief Operating Officer at Well-Safe Solutions, said: “This full-service contract is further vindication of our operating model and allows Ithaca to realise the benefits of Well-Safe’s extensive experience in the Southern North Sea.” “Well-Safe delivers environmentally-friendly and cost-effective well decommissioning operations, unlocking key learnings over multi-well, multi-operator campaigns.” “We are thrilled to have reached this agreement with the team behind Ithaca Energy, who have entrusted Well-Safe with this important project, allowing them to maintain resources on their production delivery workscopes and significant capital projects.” An option to P&A an additional three subsea wells is also available during 2023. Jane Eddie, Bid Manager, added: “We have worked closely with Ithaca Energy to design a contract which meets their needs and – crucially – those of Offshore Energies UK, the North Sea Transition Authority and wother industry stakeholders.” “Our team is uniquely positioned to support Ithaca Energy with their decommissioning obligations, as we are the first UK-based company with owner-operated rigs to exclusively perform well P&A operations.” Commenting, Ricky Thomson, OEUK Decommissioning Manager, said: “Decommissioning has a crucial role to play in helping the UK deliver its net zero ambitions, as outlined in the North Sea Transition Deal. The UK’s decommissioning industry has an incredibly exciting future ahead, and projects like this will be vitally important to realising those ambitions.” “We welcome today’s announcement by Well-Safe Solutions. We wish the project the very best of success moving forward.”
Summer 2022
In brief Canada bp will increase its acreage position offshore Eastern Canada and sell its 50% non-operated interest in the Sunrise oil sands project in an agreement reached with Calgary-based Cenovus Energy. Total consideration for the transaction includes CA$600 million cash, a contingent payment with a maximum aggregate value of CA$600 million expiring after two years, and Cenovus’s 35% position in the undeveloped Bay du Nord project offshore Newfoundland and Labrador. In Canada, bp will no longer have interests in oil sands production and will shift its focus to future potential offshore growth. bp currently holds an interest in six exploration licenses in the offshore Eastern Newfoundland region. The non-operated stake in the Bay du Nord project will expand bp’s position offshore Eastern Canada. Subject to regulatory approvals, the transaction is expected to close in 2022.
Brazil & UK Forum Energy Technologies (FET) has delivered two work-class remotely operated vehicle (ROV) sales to Brazilian marine engineering company Oceanica Engenharia e Consultoria Limitada (Oceanica) to support its deepwater intervention operations and strengthen its offering to the energy sector. The systems were manufactured at FET’s UK facility at Kirkbymoorside, North Yorkshire, and delivered in the first half of 2022. FET supplied two Perry XLX-C work-class ROV systems, both designed to deliver high performance in challenging subsea environments, adding fresh capability to the Oceanica fleet.
Summer 2022 Oilfield Technology | 5
World news Diary dates 05 – 08 September 2022 Gastech Exhibition & Conference Milan, Italy gastechevent.com
31 October – 03 November 2022 ADIPEC 2022
Abu Dhabi, UAE adipec.com
16 November 2022 Global Hydrogen Conference 2022 globalhydrogenreview.com/ghc22
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 ÌÌEM&I improves ROV performance ÌÌGD Energy Products achieves top ratings in 2022 Oilfield Products Customer Satisfaction Survey
ÌÌEni named ‘upstream industry’s mostadmired explorer’
ÌÌExxonMobil releases response to Biden’s letter to oil industry
To read more about these articles and for more event listings go to:
www.oilfieldtechnology.com
6 | Oilfield Technology Summer 2022
Summer 2022
Transocean Spitsbergen to drill for two licences Equinor has, on behalf of the Haltenbanken West Unit and Halten East licences, awarded Transocean Spitsbergen a firm drilling programme consisting of nine wells and options for another two. The value of the contract is estimated at around NOK 2.4 billion, including the options. The rig is scheduled to start the drilling campaign in the Autumn of 2023 for three production wells for the Haltenbanken West Unit, which is part of the Kristin South area in the Norwegian Sea. Subsequently, six production wells are planned for Halten East, which will be tied in to the Åsgard field in the Norwegian Sea, before considering another two wells on Kristin South. The whole drilling programme, including options, is estimated to last for slightly less than two years. Transocean Spitsbergen already has a framework agreement with continuing options and has been drilling for Equinor on a continuous basis since 2019.
EIA expects nine new Gulf of Mexico natural gas and crude oil fields to start in 2022 In EIA’s June 2022 Short-Term Energy Outlook (STEO), the company forecast that new fields coming online in 2022 will account for 5% of natural gas production and 14% of crude oil production in the US Federal Offshore Gulf of Mexico (GOM) by the end of 2023. EIA expects that GOM natural gas production will average 2.1 billion cubic feet per day (Bcf/d) in 2023, down 0.1 Bcf/d from 2022. GOM crude oil production is expected to average 1.8 million barrels per day (MMb/d) in 2023, about the same as in 2022. Currently, no GOM fields are scheduled to start up in 2023. During 2021, 15% of all US crude oil production was produced in the GOM, and 2% of US natural gas production was produced there. In EIA’s STEO, the company forecast that eight new fields in the GOM will produce both oil and natural gas by year-end, based partly on data from Rystad Energy. A ninth field, which will produce only crude oil, is expected to start in 2022. Additional capacity will not quite sustain crude oil production at levels similar to the end of 2021. The additional capacity from these new fields will not increase natural gas or crude oil production in the GOM. EIA expects GOM natural gas production to continue its three-year decline; annual GOM production last rose in 2019. Declining production from existing GOM fields is greater than the increase in production from new fields for natural gas and is equal for crude oil. Since the late 1990s, new development in the GOM has been targeting oil-bearing reservoirs. Today, most of the natural gas produced in the GOM comes from associated-dissolved natural gas production in oil fields instead of natural gas fields. In 2020, gross withdrawals of natural gas in the GOM that came from natural gas wells accounted for less than 30% of total GOM natural gas production, compared with 76% in 1999. EIA expects that the large development fields of Argos, King’s Quay, and Vito will begin production in 2022. Each has a peak production capacity of 100 000 barrels of oil equivalent per day (MBOE/d) or more, and each is the result of a focused effort to lower the costs of field developments. Offshore producers have made significant progress simplifying and standardising floating production systems and collaborating with various partners, including overseas construction services companies, to reduce total costs and remain competitive with onshore producers. However, fields expected to start in 2022 may shift into EIA’s 2023 forecast if their start-up dates are pushed back. In addition, fields expected to start in 2024 could begin earlier, resulting in changes to the company’s initial production forecasts.
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World news Coretrax completes project in USA with expandable technology Global well integrity and production optimisation expert Coretrax has completed a world record-breaking project in the Utica Basin, Northeast America, for a major gas operator with its ReLine Expandable Technology. The company successfully deployed the ReLineMNS system across three wells and expanded a total of more than 27 000 ft of tubulars across the campaign. With one of the expandable liners reaching 9000 ft in its expansion, all installations beat the previously held record of 7243 ft by at least 1000 ft. The total setting time from beginning expansion to exiting the top of the liner took only nine hours per well over a total of seven days on location. Covering the well integrity issue with one full-length liner, the overall setting time was significantly less than that of competing products on the market, setting at approximately 1000 ft per hour. Coretrax’s technology was deployed into each of the wells with a 4.25 in. outer diameter liner. On expansion of the liner, the post-expansion of the inner diameter was 4.1 in. with an internal pressure capability of well over 10 000 psi, covering the wellbore issues identified. Scott Benzie, Chief Technical Officer at Coretrax commented: “Our advanced no shoe expandable technology allows operators to effectively isolate well integrity issues and immediately proceed with their next operations without the requirement to drill out a shoe, enabling our clients access to huge time and cost savings on their projects.” “The engineered materials used in the expandable technology ensure reliability is maintained through the operation, resulting in a consistent expansion reflecting our attention to detail.” “Our highly skilled team members from the operations and applications departments were key to the success of this world record, and delivering our valuable services for each well. This project pays testament to the strong and trusting relationship we have built with our client.”
Bureau Veritas secures contract with Shell to deliver verification and acoustic noise services across offshore and onshore installations Bureau Veritas (BV) has been awarded a contract with Shell to deliver verification and acoustic noise services across 26 offshore installations and three onshore gas plants in the UK. The three-year contract, which has an option to extend for two further years, is the latest project in a long-standing relationship between the two businesses, who first started working together on this scope in 2004. The contract represents a continuation of the previous work between BV and Shell, during which BV provided Independent Verification Body services as well as decommissioning verification services for the Brent Alpha, Bravo, and Delta platforms. BV will now continue to support the decommissioning of Brent Charlie, while also providing acoustic noise services to all Shell platforms in the Northern and Southern North Sea, as well as technical integrity audit services for onshore gas plants at St Fergus, Mossmorran and Bacton. Paul Shrieve, Vice-President Global Services at Bureau Veritas Marine & Offshore, said: “This latest programme of work was secured following a rigorous tendering process and shows that even with our existing relationship with Shell, we remain both a trusted and competitive choice for them when compared with our peers.” “BV has a proud history of working in the North Sea and has been involved in many of the most important chapters in its story. As we enter the decommissioning phase for a number of assets in the region, this new contract shows there is still a role for verification in the energy industry.” The organisations have also signed up to an innovative commercial model which will see any savings made during the duration of the contract split between both parties. 8 | Oilfield Technology Summer 2022
Summer 2022
Maersk Drilling secures one-well extension for Maersk Valiant TotalEnergies E&P Suriname, Suriname Branch, has exercised an option to add the drilling of one additional well in Block 58 offshore Suriname to the work scope of the drillship Maersk Valiant. The contract extension has an estimated duration of 100 days, with work expected to commence in August/September 2022 in direct continuation of the rig’s current work scope. The contract value of the extension is approximately US$24.3 million, including integrated services provided and a fee for the use of managed pressure drilling. One one-well option remains on the contract. Maersk Valiant is a high-specification 7th generation drillship with integrated Managed Pressure Drilling capability which was delivered in 2013. It is currently operating for TotalEnergies offshore Suriname.
IWCF Drilling and Well Control Training Centre of Excellence launches in Newcastle, UK A new centre for well control training has opened in North East England to train drilling personnel in the oil and gas industry. It will be the only UK centre offering regularly scheduled IWCF-approved drilling and well control training outside of Aberdeen. AIS Survivex, part of the 3t Energy Group, has invested in a dedicated facility, along with the latest cloud-based drilling simulator technology, at its Newcastle centre where delegates can gain and maintain their well control qualifications. The facility, which has been accredited by the International Well Control Forum (IWCF), is affiliated to AIS Survivex’s Well Control Centre of Excellence in Aberdeen and will deliver scheduled level 3 and level 4 IWCF well control courses. Well control certificates are mandatory for drilling and associated personnel working in the oil and gas industry and need to be renewed every two years to demonstrate levels of well control competency are being maintained.
Prateek Pandey, Rystad Energy, Singapore, considers how upstream activity in Southeast Asia could be revived after the market shocks caused by the COVID-19 pandemic, and details the region’s production outlook and investment focuses.
Bouncing Back
10 |
S
outheast Asian countries have been reviewing ways to revive the upstream oil and gas activity in the region after the market shocks caused by the COVID-19 pandemic, including fiscal terms, incentive changes and improved bidding policies – all based on industry feedback. This creates an opportunity for some exploration and production players to expand their portfolios in the region, while others may seek to restructure
and divest non-core assets. Progress on planned developments will be crucial to revive investments in Southeast Asia. Although the outlook for sanctioning is strong from 2023 onwards, E&P players in the region will have to overcome a flurry of challenges to progress these developments. The interest from international players such as BP, Shell, ConocoPhillips, and OMV in exploration bidding rounds has come as a surprise to many, but is likely a result of
recent changes to policies and fiscal terms. A successful bidding round can pave the way for improved investment in exploration areas and potentially the discovery of additional resources.
Production outlook
Oil and gas production in Southeast Asia fell to less than 5 million boepd in 2021, representing a 4.5% year-on-year decline. This followed an 8% annual
| 11
slump in 2020, which was the region’s biggest drop in production in almost three decades. The 2020 decline was triggered by the pandemic, however even with prices and demand recovering, most countries in the region have found it challenging to bring production back to pre-COVID levels. Liquids production in Southeast Asia has been declining for almost two decades due to a lack of new discoveries and project sanctioning. By contrast, operators managed to maintain natural gas production at around 20.8 billion cubic feet per day (Bcfd) between 2009 and 2019. The region’s gas sales volumes were expected to recover last year as additional volumes from sizeable new developments came on stream, countering the 8% fall in production the year before.
Figure 1. Southeast Asia’s oil and gas production by lifecycle. Source: Rystad Energy UCube.
However, instead, gas sales volumes from Southeast Asia fell by about 3% from 2020 to 18.6 Bcfd. Indonesia’s average gas liftings for 1Q22 were 5.3 Bcfd, around 9% lower than its average gas lifting in 2021. Liquids liftings fell even further, shrinking about 13% in the first quarter to 612 000 bpd compared with the same period last year. 1Q output dropped 14% at Indonesia’s largest producing block, Cepu, while average lifting at the main gas block, Tangguh Block, declined 16%. Another key block, Mahakam, recorded a slump of 7% in the average lifting volumes during the first three months this year. Operators plan to drill over 900 wells in 2022 to optimise output volumes, up from around 500 wells drilled in 2021, which was already a step up from the average activity levels in the years before. This year’s spike in drilling activity is largely due to Pertamina taking control of the Rokan Block and approval of incentives for the Mahakam Block to support consistent investments – these two blocks account for about 70% of the total wells planned in 2022. Malaysia’s first-quarter gas production was around 7.05 Bcfd, up 8% from the 2021 average. Liquids output was around 513 000 bpd, showing little change from the 2021 average production. Gas production has gained some momentum in recent months with increasing volumes from new developments, while a recovery in liquids production was again impacted by unplanned maintenance at oilfields in Sabah. Elsewhere in Southeast Asia, additional uncertainty lingers over the performance of blocks in Myanmar amid an exodus of international oil companies, and in Vietnam due to the share of Russian players operating some of the top blocks. Unplanned outages have also been a concern so far in 2022, with shutdowns at Tangguh LNG and the Rokan and Cepu production sharing contract (PSC) areas in Indonesia, and at the Gumusut-Kakap field in Malaysia. The delay in production from new developments like Jambaran-Tiung Biru (JTB) and Tangguh train 3 in Indonesia will further challenge the potential for a year-on-year recovery in produced volumes from the region.
Investments: Challenging projects hold the key
Figure 2. Development drilling in Indonesia by operator. Left axis – number of wells; Right axis – thousand barrels of oil equivalent per day. Source: Rystad Energy research and analysis.
Figure 3. Sanctioned resources in Southeast Asia by approval year. Source: Rystad Energy UCube.
12 | Oilfield Technology Summer 2022
Sanctioning of new oil and gas resources in Southeast Asia almost tripled last year, rebounding from a 45% pandemic-induced slump the year before. Final investment decisions could keep climbing this year to the highest level in a decade – if operators’ time schedules hold. A closer look at the progress on these developments and the challenges they face reveals that some of the top projects are moving more slowly than planned, which could result in this year’s sanctioned resources in Southeast Asia dropping back to 2020 levels. Last year’s sanctioning in Southeast Asia totalled around 850 million boe of recoverable resources with greenfield investments of around US$5 billion, led by offshore gas projects. This year, operators have pencilled in FIDs for 1.4 billion boe of resources with around US$8 billion of greenfield investments. Malaysia has been at the forefront of developing new projects in the region in recent years, with around 65% of the sanctioned resources since 2017, followed by Indonesia on 15% and Myanmar with 8%. This year, Vietnam is set to become a major driver with 40% of the FIDs targeted for 2022 – Malaysia and Indonesia account for 30% each. However, the progress on these developments has been moderate. If the above projects are completed in time, Southeast Asia’s sanctioned resources in 2022 could drop as low as 400 million boe, matching 2020 levels.
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Looking further ahead, there is potential for a strong recovery with some major developments in the pipeline by 2025. This timeline also faces some risks and challenges, however. Ongoing merger and acquisition talks may affect one-third of the volumes planned for sanctioning before 2025, while around 18% of the resources have high sour-gas and CO2 content. Other challenges such as geopolitical and border issues, unitisation, and domestic gas price policies may also influence the time schedule for these projects.
Investment focus
Greenfield CAPEX makes up around 50% of total investments planned in Southeast Asia from 2022 to 2025, with brownfield CAPEX at around 44%, and exploration CAPEX around 6%.
Figure 4. Southeast Asia capital investments by top players, 2022 – 2025. Source: Rystad Energy UCube.
The region’s three national oil companies – Pertamina, Petronas, and PTTEP – dominate these segments, with a combined share of 56% in brownfield, 35% in greenfield, and 35% in total exploration CAPEX. Malaysia’s Petronas has invested over US$8 billion in greenfield projects, reflecting its focus on new developments, whereas Thailand’s PTTEP and Pertamina of Indonesia will likely focus on investments in mature fields. Among the global majors, Shell leads with a share of around 8% in greenfield and 5% in brownfield and exploration investments. With respect to exploration, the winners in the recent bidding rounds are likely to play a significant role. Shell and ConocoPhillips are active in Malaysia, Repsol is active in Indonesia, and Eni is a major explorer in Indonesia and Vietnam.
Will Vietnamese and Indonesian projects face headwinds over the war in Ukraine?
Russia’s invasion of Ukraine and the ensuing sanctions have raised questions over future investments in the global portfolio of Russian E&P companies. Vietnam’s production outlook now reflects an additional risk as Russian players hold around 22% of the country’s production volumes and operate around 40% of the output. In the absence of additional drilling, these projects could see a decline of around 10% to 15% year-on-year, according to Rystad Energy’s well data. Overall, around 300 million boe of resources are held by Zarubezhneft and Gazprom in Vietnam and Indonesia, with 70% already in production. The concern over new developments extends to Indonesia, where recent success at the Tuna Block with planned investments of around US$500 million may face additional challenges as Zarubezhneft is one of the PSC partners.
Exploration and licensing
Figure 5. Will projects in Vietnam and Indonesia face headwinds over the war in Ukraine? Source: Rystad Energy UCube; Rystad Energy research and analysis.
Figure 6. Timeline summary for ongoing and upcoming licensing rounds. Source: Rystad Energy ECube; Rystad Energy GIS Services.
14 | Oilfield Technology Summer 2022
Around 360 million boe in recoverable resources were discovered in more than 10 Southeast Asian fields last year, exceeding the total volume discovered in 2020 by 40%. About three-quarters of last year’s discovered resources were gas or gas condensate, while the rest was oil. About 82% of the volumes were found in shallow waters, with around 86% of the finds at NOC-operated blocks. Over 90% of the new volumes discovered in 2021 were found in Miocene-Clastic formations, which is typical for the region. Indonesia, Malaysia, and Thailand all showed some recovery in terms of exploration block awards in 2021. Most of last year’s new exploration awards in Southeast Asia came with improved fiscal terms. Since the start of 2021, awards in Indonesia, Malaysia, and Thailand have added a combined 12 offshore exploration blocks, three offshore small-field assets (SFAs), and four onshore exploration blocks to the active acreage in Southeast Asia. Key international players like Shell, BP, ConocoPhillips and others have joined various local players in these recent awards, which are expected to generate spending of more than US$150 million over the next three to four years based on the initial work commitments. Interest from international players in Southeast Asian exploration opportunities has been a common theme in exploration awards since 2021, though the players’ reasons for stepping up activity varies. Some companies are targeting the region’s potential for carbon capture, utilisation, and storage (CCUS), a few are looking to expand the acreage of their existing blocks and commercialise recent discoveries, and some are targeting potential oil blocks.
The region’s countries will seek to build on this momentum through their acreage offerings planned for 2022. Malaysia has unveiled its plan to offer 14 offshore exploration blocks bundled with 15 discoveries, six clusters containing 37 discovered resources opportunities (DROs), two exploration study areas and one late-life asset (LLA) under the MBR 2022 round. Indonesia plans to auction around 12 working areas this year, with planning still underway when it comes to administrative process, fiscal changes and other bidding terms. In addition to Malaysia and Indonesia, there are ongoing bidding rounds in Thailand and Brunei.
M&A activity
Upstream merger and acquisition (M&A) activity rebounded in Southeast Asia last year following a lull in 2020 as the oil and gas industry was hammered by the effects of the COVID-19 pandemic on global demand. The total announced deal value in the region’s upstream sector in 2021 reached over US$2 billion – the second-highest value tracked in the region in five years, lagging only behind 2019, with around US$4 billion. As international players are likely to continue exiting non-core assets and NOCs look for partners to share the burden of mature blocks, the region will continue to offer M&A opportunities from assets in different life cycles. In a recent transaction, Thailand welcomed a new player into its upstream sector after Canadian independent, Valeura Energy,
agreed to buy a clutch of KrisEnergy’s assets. The purchase of two operated offshore licenses in the Gulf of Thailand could mark the start of further portfolio growth in the region for Calgary-based Valeura, given the company’s growth strategy and its leadership team’s experience from the Southeast Asian sector.
Conclusion
The additional volumes from new developments are critical to stem the production decline in most Southeast Asian countries. However, the production outlook also depends on infill drilling and projects for enhanced oil recovery (EOR). While the region looks to use CCUS technology to develop large gas resources affected by sour gas contamination, the impact of economics and climate policies to support these projects is likely to be a significant discussion point for operators. The huge investments required by NOCs in mature producing blocks might result in some additional M&A opportunities. Regional players and mid-cap E&Ps are likely to continue using this opportunity to increase production from their portfolios, and the NOCs are likely to continue looking for growth opportunities across the globe. With revised fiscal terms, additional incentives, recent M&A activity, planned sanctioning, high investments in mature blocks, and multiple bidding rounds, the region is likely to see a revival of interest in opportunities across Southeast Asia.
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A long-term preservative for the biocide toolbox
Jennifer Knopf and Dr. Ulf W. Naatz, Vink Chemicals, Germany, outline the importance of selecting the right biocide to help mitigate and control bio growth in subsurface, downhole, or topside oilfield operations.
V
arious types of microorganisms are frequently dealt with during specific processes in the value chain of oil production. Aerobic and anaerobic bacteria can be present in all water-containing fluids. They are present as planktonic or sessile species, and their life cycle eventually may lead to the formation of a complex biofilm on appropriate surfaces. Biofilms contain a variety of different species (biocenosis). Sometimes, bacteria colonise the pores within the oil reservoir and are considered ‘native inhabitants,’ and in other cases, they are introduced from the external/outside environment during oilfield operations like drilling, completion, or hydraulic fracturing (through inoculation or contamination). Many strains grow on oilfield equipment, e. g., pumps, valves, pipelines, injection wells or tank interiors if conditions are favourable. Bacteria metabolise nutrients in the fluid and thus gain energy for living. However, their chemical reactions sometimes lead to the generation of hazardous by-products like organic acids or H2S. Usually, bacteria attack the metal of process equipment in an indirect
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mode, resulting in corrosion and subsequent loss of structural integrity. Sulfate reducing bacteria (SRB) metabolise sulfate sources by forming biogenic H2S, leading to the complex phenomenon of ‘reservoir souring’. Microbiologically influenced corrosion (MIC) and related biofouling causing flow restrictions may be the consequence.
The challenge of choosing the right biocide To avoid high maintenance costs, production losses, off-spec export crude or even a shut-in of wells, a biocide treatment following ‘best industry practice’ may be considered. Biocides can help to mitigate and control bio growth in subsurface, downhole or topside operations if the right one with the appropriate combination of physical and chemical properties is selected. Oilfield biocide selection may depend on solubility/partition in the oil versus water phase, pH, salinity, thermal stability, efficacy against specific strains like SRBs, chemical compatibility with other applied oilfield chemicals, the formation chemistry, speed of kill, regulatory requirements,
downstream processes/disposal and many other factors. Designing a tailor-made biocide treatment that matches ‘best industry practices’ requires an advanced process understanding gained by conducting a sound site survey followed by application assessment.
In ‘reservoir souring mitigation’ or ‘well shut-in preparation’ the biocide does not only control the initial germ count in the fluid itself, but also provides a long-term residual activity to protect the reservoir over weeks/months against potential microbial recontamination and regrowth.
Applications
Fit for purpose
A biocide treatment can be preventative or curative. In a preventative application, a biocide is applied to a moderate-to-low bio contaminated stream in relatively low concentrations to keep the bacteria level under control and avoid the formation of established biofilm. Water reinjected into the reservoir needs to be treated to prevent potential reservoir souring from worsening. In a curative treatment, a fouled system needs to be sanitised by a combination of mechanical cleaning/chemicals assisted biofilm removal and a relatively high concentration of biocide typically applied in a shock treatment.
Biocides may be categorised as ‘quick killing,’ with their purpose being to pre-treat and decontaminate process water. A ‘best industry practice’ to reduce the initial germ load is the application of an oxidising biocide which will reduce bacterial counts within minutes (disinfection). Other treatment programmes often include organic ‘quick killing’ biocides like THPS, TTPC, Quats, DBNPA and Glut. Depending on the available contact time, other biocides like formaldehyde releasers may also be good choices. ‘Long term’ biocidal performance ensures the protection of treated water, for example, during storage or drilling,
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fracking, water flooding, EOR operations, and well shut-in, and can prevent microbial spoilage, reservoir souring, and equipment failure caused by corrosion. For this application, biocides must be compatible with challenging conditions for an extended period of time. Required protection times vary from weeks up to several months. Well-known long-term preservatives are DMO and MBO.
Benefits and drawbacks of biocides
Biocide properties must match their specific application conditions. Some biocides are not compatible with H2S present in the fluid and quickly become deactivated. Others show unacceptable foaming or may act as a H2S scavenger. Charged biocides (i.e. Quats, THPS) may get physically adsorbed onto surfaces (equipment, formation) and thus may not be available for biocidal performance
in the bulk phase. Others are not compatible with high salinity brines or become thermally degraded under higher process temperatures. Many biocide residuals are difficult to monitor under field conditions. Having simple and quick field test kits available can assist in tracking residuals and, in combination with established culture based microbial tests, help in optimising the dosing regime and thus improve cost effectiveness.
Capturing the value
This article reports application benefits of 3,3’-Methylenbis (5-methyl-1,3-oxazolidin) CAS 66204-44-2 (MBO) as a long-term preservative in oil and gas. MBO is available as grotan® OX (Europe/ rest of the world) stabicide® 71 (US)/ grotamar® 71 (fuel biocide). MBO has all required registrations/approvals including FIFRA, BPR, CEFAS and NEMS. It is a >99% active product (favourable storage and transport footprint) and has beneficial properties like biodegradability, high thermal stability (160°C), low temperature viscosity profile, oil and water solubility and a broad antimicrobial spectrum.
Experiment 1: Biocidal performance against SRB
Figure 1. Reduction of sulfate-reducing bacteria – 50 ppm MBO.
Figure 2. Biocidal performance against planktonic and sessile sulfate-reducing bacteria.
The experiment shown in Figure 1 presents biocidal efficacy against planktonic SRBs, using a mixed bacterial consortium from a production in the North Sea. The culture was grown at 30°C in a 50 000 mg/L TDS brine. The numbers were assayed using triplicate ‘most probable number’ counts. The data reveals an excellent performance at only 50 ppm dosage of MBO shown by a significant SRB reduction after 30 minutes contact time. Figure 2 displays the biocidal efficacy of MBO against planktonic and sessile SRB. For this experiment, two bottles were equipped with (A) a clean metal coupon (to check performance against planktonic SRB/biofilm formation inhibition capability) and (B) a coupon with preformed SRB biofilm (to check efficacy against planktonic SRB and detachment/killing of SRB biofilm). The recovered SRB was enumerated by serial dilution (MPN method; NACE TM0-194 (2014)). The graph shows MBO’s biocidal performance against planktonic SRB, inhibiting the growth of an SRB biofilm, and detaching and killing preformed SRB biofilm. In this set up, to eliminate planktonic SRB within four hours contact time, a dosage of 100 ppm MBO was sufficient. Performance against SRB biofilm requires either 100 ppm/24 hours or 300 ppm/4 hours of MBO.
Experiment 2: Hydraulic fracturing Figure 3. A 0.025% MBO dosage has no negative impact on viscosity properties under the test conditions with this specific frac formulation. Additional retesting after 3 days of storage came to achieve similar results.
18 | Oilfield Technology Summer 2022
Using a biocide in hydraulic fracturing applications requires specific product properties like compatibility and stability with the frack fluid, and most importantly, a cost-effective biocidal performance.
Figure 3 shows that a 0.025% MBO dosage has no negative impact on viscosity properties under the test conditions with this specific frac formulation. Additional retesting after three days of storage showed the same results. Figure 4 presents the stability and long-term activity of MBO compared to the commonly used biocide glutaraldehyde. Both biocides were mixed with a frac water and stored over a period of 70 days at elevated temperatures of 75°C. Long-term stability was proven after the storage period by checking the biocidal activity. The graph shows the reliable long-term activity of MBO in a frac water. The goal of the test in Figure 5 was to identify a biocide that could effectively reduce the initial germ load, handle a rechallenge and eventually offer full protection of the system by inhibition of bacteria regrowth over the entire duration of the test. As seen in the graph, a dosage of 250 ppm DMO (a. i.) shows only limited germ reduction after the first and second inoculation. This dosage is not sufficient to inhibit regrowth of bacteria, resulting in a fully contaminated system after a couple of weeks. In contrast, 250 ppm (a. i.) MBO shows full biocidal efficacy after 24 hours contact time after the first inoculation. The same performance is determined after the reinoculation. This dosage is sufficient to protect the system against regrowth of bacteria over a period of approximately two months. To achieve all of the goals previously outlined, either 500 ppm (a. i.) of the biocide DMO or 250 ppm (a. i.) of MBO is required. Since DMO is commercially available as a 74% aqueous solution, this adds up to a correspondingly higher dosage rate of 676 ppm.
Figure 4. The stability and long-term activity of MBO compared to the commonly used biocide glutaraldehyde.
Conclusion
Many studies have reported varied resistance levels to biocides commonly used in oil and gas referring to consortia enriched from produced water samples, indicating a specific response to each biocide. This translates into the need for new biocide chemistries or for the concept of combined treatments (with more than one chemistry) to be applied. With availability of more biocides in the ‘toolbox’, resistance can be bypassed. Based on the data presented above, Vink Chemicals performed a field trial with MBO in a matured well treatment. The biocide was injected into the near wellbore area and allowed to soak for several hours. Tracking the produced fluids from this well in terms of residual active (specially designed field methods) compared to ATP levels demonstrated the suitability of this biocide under typical field conditions.
Figure 5. A dosage of 250 ppm DMO (CAS51200-87-4 / 4,4-Dimethyloxazolidine) shows only limited germ reduction after the first and second inoculation.
Figure 6. Field test data/North Africa region.
Summer 2022 Oilfield Technology | 19
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Roar Pedersen, Andreas Fliss, and Fernando Zapata Bermudez, Archer Oiltools, Norway, explain how the development of a packer, as part of the drilling BHA, could help overcome the challenges involved with drilling depleted reservoirs.
O
ne of the oil and gas industry’s many challenges today is to sustain and extend production from existing fields and installations by maximising the recovery of the reserves left in the ground. This helps to reduce costs by reducing the need for investment into exploration and development of new fields and has a positive impact on the overall CO2 footprint, contributing to a more sustainable future for the industry. The recovery factor is the overall proportion of oil and gas expected to be recovered from the reservoir, versus the total amount of proven and probable reserves. Norway has achieved a remarkable increase in the overall oil and gas recovery from its fields on the Norwegian Continental shelf over the past decades from about 30% to currently more than 47%.1
Rising To The Challenge | 21
Figure 1. Pressure depletion.
Infill drilling is one of the options for operators looking to achieve an increase in oil and gas recovery from existing fields. There are a number of technical challenges to overcome in order to achieve efficient drilling in mature fields, such as limited or even nonexistent drilling windows. It is estimated that 20% of Equinor’s IOR volume is connected to infill drilling and depletion challenges. Figure 1 shows a typical pressure depletion scenario. In essence, the challenge is to improve operators’ confidence in drilling within a limited drilling window, and avoid uncontrolled risks. The drilling window is the difference between the maximum pore pressure and the minimum effective fracture pressure of the formation. Drilling practices rely on maintaining a pressure in the annulus to prevent formation fluid from entering the borehole and at the same time, avoiding the fracture of the formation being drilled. Drilling in depleted reservoirs is complex and is influenced by a variety of parameters such as pore pressure, rock stresses, fracture pressure, cooling effects due to injection, shear failure/bore hole stability, loss mechanisms, geological complexity, drilling fluids, drilling technology, operational practice, and production strategy amongst other factors. Figure 2 shows a typical drilling window.2 To overcome the challenges of drilling depleted reservoirs, new technology was needed as part of a cost-effective solution. An innovation campaign was facilitated by Equinor R&T (research and technology) to identify concepts enabling high depletion in drilling through reservoirs. Several concepts were evaluated, and a packer in the drillstring was defined as a necessity by Equinor.
Product development
Figure 2. Drilling window.
Figure 3. Pressure depletion and stress changes.
22 | Oilfield Technology Summer 2022
Drilling through depleted reservoirs has become more and more common in operations run by both Equinor and other operators, as many of their fields have matured. Drilling these wells introduces an increased risk for crossflow and losses and a series of mitigating actions have been put in place to obtain an acceptable risk level. With the complexity of the wells increasing, the risk level has also increased, to a stage where a few assets could no longer find existing mitigating actions to support a sustainable operation. Operators at the Gudrun and Kvitebjørn sites contacted Equinor’s R&T department with a request to investigate a development of a packer to be included in the drilling BHA, and as such provide the additional mitigating action required to continue the planned operations in a safe manner. Through a tender process, Archer Oiltools was chosen based on the company’s relevant history supplying bridge plugs and packers, cost and development time. Time was crucial as the technology had to be ready prior to the upcoming drilling campaigns. As part of the scope of work, the packer had to be part of the drill string and withstand the same forces as other components when drilling the reservoir section. This is unique and made it especially challenging as packers and plugs are usually exposed to static conditions prior to setting, while the packer to be developed had to withstand all the erosive forces caused by rotation, circulation, vibrations, tripping and so on. It was also specified that the packer should not be a limiting factor in the string with regards to ID, OD, tensile, compression and torque. It was agreed early on that the design would be kept simple and robust using well-known principles from existing packers and plugs.
To ensure that no critical areas of the packer were exposed to high levels of erosion, Computational Fluid Dynamics (CFD) were conducted during the design phase (Figure 4). The CFDs have been set up with various circulation rates and with mud properties comparable to actual well conditions. The extended testing carried out with the prototype packer showed no signs of any wear to critical components such as the element, slips or ball seat, in line with the results from the CFD analysis. Besides the factory acceptance testing performed on both component and assembly level throughout the entire development process, the packer has gone through three full scale test cycles.
A design change was made to the element to reinforce it and help it withstand the high extrusion gap at elevated temperatures.
Full scale test at NORCE (Ullrigg Test Centre) in January 2020
Test results
Field trial Kvitebjørn A-10 in July 2021 Objective
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The packer was run as part of the BHA as planned and operation was completed. The packer was brought onshore and set in a test casing without any cleaning after being retrieved from the well.
Objective
ÌÌ ÌÌ ÌÌ
Include the packer in the BHA for drilling out the cement plug and 3 m of new formation. Bring the packer onshore after completing the drilling. Set it and pressure test it in a test casing and subsequently bring it to a third-party facility for an ISO14310 V3 qualification.
Expose the packer to realistic conditions with rotation and circulation over six continuous days. Activate, set and perform a pressure test. Release and pull back to the surface.
Test results The packer was run into well U-2 of the NORCE test facility to a depth of 1000 MMD. The well was filled with 1.7 sg WARP OBM. The packer had an established rotation of 120 RPM and circulation of 1600 LPM. These parameters were set for six days, only interrupted by two trips to surface for visual inspections. The packer was then activated and set, pressure tests were performed, and the running tool was released. The running tool was then re-attached and the packer was released and pulled back to surface. The test was carried out according to the planned test procedure. Some minor issues were experienced when releasing the packer, which led to a design upgrade, making the packer more resistant to debris or additives in the mud.
Figure 4. Computational Fluid Dynamics analysis.
Field trial Gudrun A-8 in May and June 2020 Objective
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Running the packer as part of the BHA, and drilling the reservoir section exposing the packer to the drilling environment. Bringing the packer onshore after completing the drilling. Setting and pressure testing and subsequently bringing the packer to a third-party test facility for an ISO14310 V3 qualification.
Test results The packer was run as part of the drilling BHA in well Gudrun A-8 as planned. As it was only planned to be exposed to the drilling environment, the packer was locked to prevent unintentionally setting, as a risk mitigating action. A total of 250 m was drilled at 1200 LPM circulation and 80 – 100 RPM in MPD mode. Some drilling challenges arose as a total loss scenario was encountered, and several contingencies were implemented to cure the severe losses. The packer was eventually retrieved to surface after 20 days in the well and a visual inspection showed no sign of wear or damage. The packer was brought onshore and set in a test casing in the exact condition it was in when retrieved from the well. An in-house pressure test to 200 Bar was successful and the packer was brought to NORCE for the ISO14310 V3 test. The packer passed a 200 Bar pressure test at 135°C from below, but experienced a leak when pressure tested from above.
Figure 5. When set, the DASP provides a seal between the drill pipe and the
casing.
Summer 2022 Oilfield Technology | 23
An in-house pressure test to 200 bar was successful and the packer was brought to NORCE for the ISO14310 V3 test. Testing at NORCE was successfully completed in three steps: 100 Bar differential pressure at 135°C. 100 Bar differential pressure at 150°C. 200 Bar differential pressure at 150°C.
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The development stretched over two years, where Archer worked in close co-operation with the R&T team and the assets in Equinor. Milestones had been set in relation to concept studies, design reviews and testing. The qualification testing included component testing, full scale tests and finally extensive field testing at both Gudrun and Kvitebjørn. This was the most extensive packer qualification programme to date by both Archer and Equinor.
Technology
The packer was branded DASP, short for Drillstring Annulus Sealing Packer. As the name indicates, the packer, when set, provides a seal between the drill pipe and the casing. Float valves will provide the internal seal. The DASP is qualified according to ISO14310, validation grade V3. The basic design of the DASP bears many similarities to the Archer LOCK series plugs. The slips anchoring the packer, the element providing the seal, the lock segments locking in the setting forces and the J-slot design for the dis-and reconnect function of the running tool are all based on the LOCK design. In addition, features to prevent unintentional activation and disconnect are similar to the design in the Archer VAULT dual plug system. In addition, several safety features and components have been added to allow a safe operation in the drilling environment. As highlighted, activation of the DASP is meant to be the last option in a series of mitigating measures as the wellbore will be abandoned if activated. This requires the DASP to be positioned in a cased hole at a depth with sufficient formation and cement integrity. The current version of the DASP is fit for exposure to and setting in a cased hole. Evaluating further qualification, a second generation will be exposed to
open holes and still be set in a cased hole, and a third generation will be exposed to and set in an open hole. The DASP is ball drop activated and hydraulically set. When the DASP is fully set, the drilling BHA is suspended below. The running tool is released from the DASP and operation can be completed by placing cement on top. Key capabilities of the DASP include: 9 5/8 in. & 9 7/8 in. casing size. ISO14310 V3 qualified. 200 bar differential pressure rating. Can withstand temperatures of up to 150°C. 250 MT tensile capacity. Qualified for up to 180 RPM. Qualified for circulation rates up to 1800 LPM. Hydraulically activated and set. High torque rating. Disconnect and reconnect function. Resettable and retrievable. Millable.
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Conclusion
The DASP is a technology that provides a seal between the drillpipe and the 9 – 5/8 in. or 9-7/8 in. casing. It is part of the drilling BHA and is spaced out to stay inside of the casing. Its large bore allows high flow rates and deployment of intervention tools through it. By setting the DASP, it becomes a qualified V3-barrier, enabling the operator to cement and sidetrack efficiently, saving additional trips and rig time. This technology is set to help Equinor to expand its capabilities for drilling depleted and complex reservoirs and further increase the overall recovery factor for its mature fields.
References 1. 2. 3.
Effective resource management in mature areas - Norwegianpetroleum.no (norskpetroleum.no) 31.03.2022. Presentation given in the Equinor Network Meeting - IEA Gas & Oil Technology, Offshore Mature Fields – Extended Life and IOR, Trondheim 08 June 2017. Equinor internal publication - Extra well informed, issued February 2022.
Improving bit by bit Dustin Lyles, Brandon Sheldon, and Casey Kitagawa, Taurex Drill Bits, USA, explain how the evolution towards digitalisation and analytical evaluation has impacted drill bit performance.
I
n the field of oil and gas exploration, the drill bit industry is constantly innovating, driven by the challenges of wells that are growing in complexity and difficulty. For decades, drill bit product development has sought to improve drilling performance, using iterative design changes to drive incremental gains in performance metrics such as rate of penetration (ROP). The industry has moved toward digitalisation and analytical evaluation while developing better tools and improved drilling systems that impact drill bit performance. This evolution has exposed deficiencies in the traditional product and cutter development process, necessitating a more scientific approach to drill bit design. One area in which critical strides have been made is drill bit forensics. This area covers the practice of analysing post-run data to provide a more in depth look into the main performance-limiting factors such as downhole drilling dysfunctions and other phenomena, bit wear and damage,
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cutter condition, bottom hole assembly (BHA) conditions and so on, that, when taken together, can truly enable a better understanding of the drill bit as it relates to the whole drilling system. Understanding these complex relationships was previously a time-consuming and murky proposition at best, often relying on poor quality 2D images, field dull grades, and daily drilling reports with inconsistent and often inaccurate data manually entered by humans. This approach to forensic drill bit analysis resulted in a high degree of subjectivity in data collection and conclusions, but was also not easily scalable for high volume bit run analysis due to its laborious nature. This made developing an optimisation strategy an exercise in guesswork and/or trial and error-based development. Furthermore, the time taken to walk through such a time-consuming process made it extremely difficult to evaluate dull drill bits at scale.
To achieve the objective of providing the industry with an automated platform for analysing bit dulls and using collected data to drive iterative improvements in bit body and cutter design, Taurex Drill Bits introduced its proprietary digital dull evaluation solution for forensic analysis, the Automated Metrology Laboratory™ (AML) (Figure 1).
Technology
As part of the company’s ongoing digital transformation, Taurex is leveraging AML to replace traditional methods of bit and cutter analysis and subsequent design improvements with data-driven and objective decision making. When a post-run drill bit arrives at its central repair facility, a robotic metrology-grade optical laser scanner captures point clouds that are converted to a 3D polygonal mesh model and the wear state of the dull bit is digitised, measuring wear to within three thousandths of an inch.
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This digitised wear data is then linked to the specific application for which it is used along with performance data in Taurex’s server-based data repository, where it can be combined, sorted, analysed, and scaled to quickly identify trends alongside other runs in the same application. The digitised wear data can then be tethered to any of the multiple design characteristics for a given part number, such as back-rake, work rate, cutter spacing, and others to model and identify the most effective direction for iteration. The comprehensive relational database is now supplying the Taurex team with a digital feedback loop through a growing amount of wear, performance, and application data. Bit engineers and designers can now use the models to produce bit designs with predictable performance differentials, scaled in comparable drilling scenarios, as bit designs are iterated. The digital feedback loops created through this ongoing process, and the time to collect, process, and upload to the analytics tools, takes less than 20 minutes after being received at a Taurex facility, shaving days off the time it would have taken engineers to manually perform these tasks in the past. Because every dull bit is systematically evaluated with such precision and accuracy in a scalable manner, AML allows for improved bit designs in step with industry demands while ensuring that the gap between science and engineering is bridged, enabling new knowledge acquisition during the engineering process. Not only has the increase of information bolstered case studies within existing engineering domains but it has also enabled engineers to delve into new data-driven approaches. One such
Figure 1. Taurex’s Automated Metrology Laboratory (AML) is an automated 3D robotic scanning process capable of producing digital dulls with precise wear measurements on individual drill bit cutters. The resulting data supports a digital feedback loop to facilitate bit forensic analysis and continuous improvement for Taurex and their customers.
developing method is the tethering of electronic drilling recorder (EDR) data to bit-design variables and forensic dull analysis. This multi-factor combination of data enables the potential to generalise expected run performance via machine learning methods to an accuracy that enables predictive bit degradation and overall drilling system interactions.
Case studies
AML has been effective in several cases, with digital dull capabilities clearly enabling improved drilling performance and reduction in diamond loss. In a 12¼-in. curve application in the Midland Basin, US, the operator was challenged to build angle with a large-diameter bit and BHA. Using data from the benchmark bit, AML identified a consistent problem area which was leading to a loss of build-up rates and reduced ROP. Using AML to establish the exact location and root cause of the cutter damage allowed for a new cutter design to be implemented in the precise location of interest that could better withstand the forces causing the cutter damage, resulting in a 42% increase in ROP and a 40% reduction in diamond area removed (DAR) in a direct offset comparison (Figure 2). In a Delaware Basin Wolfcamp curve interval, an operator encountered directional challenges with highly interbedded carbonates coupled with immense lithostatic and hydrostatic pressures. These downhole conditions often result in tool face control issues, in turn causing decreased build rates and increased slide times. In the worst cases, unplanned trips were also necessary. Using AML data, Taurex was able to determine precise wear measurements for the cone depth-of-cut control (DOCC) feature, then adjust their placement based on the findings. The new design, with the DOCC features in an optimised location, helped ensure that the operator had better tool face control when facing similar conditions on the following well. In another project, AML was used as a learning tool, with precise wear quantification enabling rapid acceleration of cutter testing and development. Using AML to quantify the exact amount of DAR on the test cutter compared to adjacent cutters in a paired-cutter test allowed for exact comparisons, clarifying a 47.7% improvement in DAR. Traditionally, multiple test runs were necessary to determine whether a cutter was suited for an application, and the standard visual approach to field cutter test analysis would have been unlikely to identify such a significant performance differential in such a short amount of time. In this case, AML was the catalyst for an increase in speed of learning (Figure 3).
Innovation validation
One area in which AML is showcasing its potential to disrupt the industry is through the validation of a new cutter design. Taurex had been researching the potential of a 14.5 mm cutter, with early tests showing that this size achieved more consistent reactive torque and enhanced tool face control versus 16 mm cutters. 14.5 mm cutters are also capable of higher top-end ROP than 13 mm cutters due to increased available depth of cut. Furthermore, Taurex found that the 14.5 mm design had improved directional efficiency in the lateral versus the 16 mm design because it decreased the number of necessary slides and increased slide ROP. Early runs in the Midland Basin have shown promising results. In a vertical curve application, the newly designed Figure 2. In a challenging 12 ¼ in. build section, AML data provided an insight 14.5 mm cutters helped achieve a rotating ROP of 425 ft/hr in into the precise location and cutter damage modes that were limiting build-up the vertical section and sliding ROP of 150 to 200 ft/hr in the rates and rate-of-penetration (ROP). This insight led to implementation of a new curve. The bit equipped with the new cutters most recently cutter design to combat the specific damage modes observed, resulting in a 42% drilled 2880 ft in 16.75 hours while building the curve to casing increase in ROP and a 40% reduction in Diamond Area Removed (DAR).
26 | Oilfield Technology Summer 2022
A Team with Our Customers
point on 9 to 11°/100 ft build rates. Implementation of the new 14.5 mm cutter vertical curve design resulted in 100% interval completion rate for the operator. Using AML allowed for optimisation and validation of the cutter design that could be scaled across comparable wells in the Midland Basin. In the 8½-in. section of Lower Spraberry laterals in the Midland Basin, the operator found that the standard Taurex 6-blade, 16 mm cutter configuration excelled for footage drilled, ROP, and tracking/directional performance. This design was thus used throughout the operator’s applications. However, once the data was analysed by AML, it was clear that there were two distinct opportunities for improvement. Correlations between cutter spacing and sporadic cone damage were identified, while theoretical torque curves on the outer nose corresponded to increased DAR, indicating more diamond volume was needed to mitigate cutter wear. A design strategy was selected based on the AML findings, specifically to maintain a good ROP and directional/tracking response of the initial bit design while allowing for purposeful adjustment of identified design variables to improve DAR. Furthermore, implementation of the new 14.5 mm cutter in these applications, combined with AML-identified design strategies above, allowed the new bit and cutter configuration to outperform the previous design, with a 6.6% increase in footage drilled, 19.2% increase in ROP, and 44.4% decrease in DAR (Figure 4).
Figure 3. The ability to evaluate cutter wear with precision allows for accurate and rapid cutter development and field testing. In this case study, paired cutter testing was conducted, exhibiting a 47.7% reduction in DAR on low wear state cutters that may have been overlooked if traditional, visual wear comparison methods were utilised.
Conclusion
As the oil and gas industry continues its trend toward digitalisation and more analytical decision making, the drill bit sector will continue to evolve with drilling performance and wellbore quality driving the need for better designs with less iterations. With the introduction of AML, data-driven bit design improvements and rapidly scalable enhancements have been seen throughout the industry.
Figure 4. The introduction of the 14.5 mm cutter design bridges the gap between ROP, durability, and directional trade-offs associated with transitions between traditional 13 mm and 16 mm cutter sizes. Actionable insight gained from analysis of AML data for over 60 runs utilising a successful 16 mm cutter design exhibited a clear path for deployment of the new 14.5 mm design that resulted in substantial reductions in DAR, delivering improvements in both durability and ROP.
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Seeing Past Traditional Approaches Matt Rothnie, Vysus, UK, examines how rig selection for well decommissioning can be influenced by the development of a ‘fit for purpose’ well abandonment philosophy, alongside optimised unit selection.
U
nit selection in recent times has mostly been a straightforward task with a plentiful supply of units available to operators at knock down rates. However, with the upswing in rig demand driven by a recovery in commodity price and renewed security of supply concerns, the task is set to become more challenging.
As mature basins including the North Sea enter a chapter where decommissioning projects are competing with more value adding new developments and barrel-chasing opportunities to secure rigs and operational units, it is essential to ensure that all the potential solutions are considered, and the most effective solution is selected to ensure project success. The OEUK Decommissioning Insight 2021 report1 indicated that in the next decade, 1782 wells would need to be abandoned. Assuming a nominal estimate of 20 days to abandon each of these wellbores, this results in the potential for over 97 years of operational scope. This has driven the need to ensure available units are assessed, in order for efficient decommissioning projects to be executed. UK demand alone could fully utilise the existing rig fleet for several years. Globally speaking, according to rig analysts, Esgian, rig demand is on the up, with the North Sea being earmarked as one of two hotspots. Though a dramatic
surge in demand is unlikely, activity in the near-to-mid-term is expected based on the price of US$80/barrel. Esgian also illustrates that a revisiting of shelved projects is likely, with the North Sea’s Cambo oilfield being a prime example. This will mean an uptake in either constructing new rigs from scratch or reactivating cold/warm stacks. Operators will have to face up to a distinct lack of options when it comes to rig selection in addition to rising costs and less flexibility on timing. Simply pushing out decommissioning activity and deferring costs may solve problems in the short term, however this may not meet the agenda and commitments provided to regulatory bodies and environmental stakeholders. One question this current market environment raises is, ‘how can the oil and gas sector adapt to meet the changing market dynamic?’ One area to be explored further is the use of rigless approaches for platform operations.
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Recently in the UKCS, a shift towards rigless approaches for platform multi-well decommissioning has been observed. The capability of modern equipment such as Modular Drilling Rigs (MDR) now overlaps with tasks which previously could only be performed by full rig packages. Modern MDR units also provide the advantage of hands-free operations, which provide added safety benefits, in turn improving all platform lifecycle projects. Establishing if a rig-based approach is essential or not can potentially remove the costly option of platform rig reactivation and the rental of an MDR also eliminates ongoing operating, maintenance and recertification costs on existing drilling facilities. Jack-up options also pose interfacing challenges with regards to both the platform structure and the subsurface infrastructure. Increased schedule risks can occur due to the availability of this unit type, as only certain jack-ups may be suitable for the subject platform, and due to the weather vulnerability of jack-up locating operations. The recent upsurge in the use of jack-up rigs to drill subsea development wells caries the potential result of increased day rates and decreased availability. Another opportunity is to draw on global experience in abandonment unit selection and apply this to the entire oil and gas project lifecycle, moving away from traditional thinking and instead taking a more risk-based approach, evaluating all available operational units which can offer safe, effective and cost-efficient methodologies. Internationally, operators have yielded significant project savings by utilising dynamically positioned rigs over conventionally moored units. Such selection, when coupled with fit for purpose subsea well control equipment, could enable DP units to be less constrained in operating in shallower water, thus saving considerable time for mooring and rig move operations.
Case study 1 Client challenge The client, a large North Sea operator, required an effective abandonment solution to be developed for 35 platform wells with various challenges including sustained annular pressure, scale issues, and collapsed casing. The subject platform did not have an operational drilling package available.
Approach Senergy Wells, a Vysus Group company, completed an evaluation of the available unit options versus the well abandonment design requirements. It was assessed that for the required well abandonment scope, an MDR presented the best solution for the client. A partnership with a leading platform drilling contractor was established. The MDR units offered by the contractor were built in accordance with the NORSOK D-001 Drilling Facilities Standard and have successfully delivered a series of wells up to 6.6 km (>21 500 ft), as well as permanent P&A operations including multi casing and conductor string recovery. The drilling contractor provided facilities support with regards to the installation of the MDR unit onto the client platform which worked hand-in-hand with the well engineering support provided by Senergy Wells.
Results By integrating with the platform drilling contractor and ensuring positive engagement with the client, Senergy Wells developed: Detailed well abandonment basis of design, including engineering modelling of well conditions versus the capability of
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30 | Oilfield Technology Summer 2022
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the selected MDR unit for both the base case well abandonment programme and possible required contingency operations. Well abandonment programmes, for the execution of the above. Well cost estimate, demonstrating the time cost savings for the client.
These well engineering deliverables were supported by a full derrick removal study to enable the installation of the MDR unit onto the platform and detailed MDR installation and integrated engineering studies.
Case study 2 Client challenge Senergy Wells conducted a conceptual study for the abandonment of a 15 well deepwater subsea development. The study was to include a full conceptual well abandonment design as well as conceptual cost analysis for completing the programme. The project was to be completed within the allotted six-week time period. Despite the challenge of delivering the extensive workscope to a tight deadline, all the work was completed, not only the well abandonments, but part of the wider decommissioning including wellheads and trees.
Approach Using an experienced project team balancing deepwater and abandonment proficiency, the key aspects of the study delivered were: The recommended standard on the abandonment philosophy. Complete well designs including detail on re-entry to the wellbore, de-completion, and setting barriers (including the reasoning and positioning in the wellbore). A full risk assessment process evaluating higher risk items such as abandonment thru-tubing options and removal of trees under single barrier isolation. An assessment of equipment that could justifiably be left in situ. An overview and consideration of the complexities involved, given the use of both vertical and horizontal trees as well as the technical implications on unit selection. Fully justified recommendation on light well intervention vessel vs dynamically positioned MODU vs anchored MODU strategy.
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Results
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The company identified the opportunity to leave equipment in situ, saving approx. US$10 million in operational time across the 15 wells. The potential to avoid temporarily suspending the wells was highlighted when moving to full abandonment was more cost effective. A potential saving of US$50 million was calculated. The comparison of LWIV vs DP MODU vs anchored MODU not only highlighted the potential direct cost savings but also the potential to reduce operational risk in tackling unexpected situations.
Operational unit selection has taken on a new role in the changing world of energy. Challenging the conventional approach both from a technical and commercial point of view will be needed to ensure companies responsibly deliver safe and efficient well decommissioning.
References 1.
https://oeuk.org.uk/wp-content/uploads/2021/11/Decommissioning-Insight2021-OGUK.pdf.
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Don’t ditch the data D
ata analysis and artificial intelligence (AI) could be seen as the key to safe and efficient integrity management. Often when data is collected, a large proportion of it goes to waste, along with the costs and risks of gathering it. A reason for this is that the prescriptive regulations calling for the data represent a shotgun approach based on the lowest denominator in terms of asset condition; in other words, lots of data is gathered, and one or two useful pieces of information that confirm base compliance are found, meaning the rest is discarded. The second reason is that until analysis and AI became more widely recognised and understood, data had been seen as too difficult to analyse quickly or cost effectively. The third reason is that new, robotic, and remote inspection methods gather more data than ever, which could be perceived as overwhelming.
What is the oil and gas industry doing to remedy this? The JIP (Joint Industry Project) for HITS (Hull Inspection Techniques and Strategy) has stimulated thinking on
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this topic due to the increasing applications of remote technologies that collect vast amounts of data for analysis, providing useful insights into asset condition and trends. There are a number of challenges regarding data and metadata. How should it be collected? How frequently? By what methods should data be collected? And how should it be managed and analysed? Many of these questions can be addressed through using a risk based integrity strategy rather than following prescriptive rules.
Risk based strategy
Risk based strategies for assuring equipment integrity are efficient because they target known critical areas. This makes RBI and remote inspection systems highly compatible, avoiding the gathering of unnecessary data. However, RBI does require knowledge of the equipment design, inspection, maintenance, and operating history.
Danny Constantinis, EM&I Group, Malta, explains how data analysis and AI combined with RBI strategies and robotic data collection systems could become the future of asset integrity management in the oil and gas industry.
How would an RBI approach work for a floating offshore asset such as an FPSO?
Rather than follow prescriptive class rules that require inspection data irrespective of the specific integrity risks of the structure, the RBI approach focuses on gathering data relevant to the structure in question. An RBI inspection plan and work pack will be developed by a group of people knowledgeable in the RBI process and experienced in the history and operation of the asset. The inspection plan identifies the ‘what, how, and when’ of the data gathering process, generally seeking to extend inspection intervals where appropriate. Often, the increased inspection intervals may be contingent on some form of confirmatory visual inspection, and this is where remote systems such as NoMan and UAV come into play.
What data needs to be collected and how?
In the case of structural integrity on an FPSO, visual inspection, distortion, thickness, and coating data may be collected, however
metadata such as the loading condition, ambient conditions, sea state etc., should also be considered. The collection of inspection data is a rapidly changing topic being discussed across the industry in JIPs such as HITS (Hull Inspection Techniques and Strategy). Key drivers include safety, cost, sustainability, and environmental aspects, and especially emissions reduction. Workers should not be put at risk through working at height, in confined spaces, or in dangerous environments such as working underwater to gather integrity information. It is often difficult to justify the benefit of inspections to protect life when there are fatalities involved in gathering the data to do so. Solutions to this dilemma include using robots and modern, data gathering technology such as remotely operated cameras and laser scanners to gather data. This type of solution goes a long way to resolving the second challenge of cost and operational efficiency. Making an environment safe for humans is much trickier than making it available for a robot.
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Figure 1. NoMan remote camera .
Figure 2. UAV tank inspection.
Figure 3. Typical integrity class ROV.
34 | Oilfield Technology Summer 2022
For example, the time taken to clean and make a confined space, such as a cargo oil tank, safe for human entry could take weeks for a team of people, all the while being exposed to safety risks and making the tank unavailable for operational use. NoMan deploys remotely operated robotic cameras that can carry out a confirmatory visual inspection in a matter of hours without the safety risk and time-consuming activity of preparing for man entry into the confined space of a structure. The visual data gathered can be supplemented by synchronous laser surveys that define the shape, size, deformation and thickness of the structure, coatings, tank cleanliness, etc., thus providing the current condition status and an accurate assessment of future trends. From a practical perspective, tank cleanliness is vital to gathering meaningful data; this is extremely important for the bottom plating structure, which is difficult to clean and susceptible to pitting corrosion. Similar arguments apply to diverless solutions for underwater surveys, as diving is a hazardous activity with fatalities regularly recorded. Modern Integrity Class ROVs gather visual, NDT, corrosion protection and dimensional data, without putting people at risk. Ongoing developments are increasing the capabilities of these robotic subsea systems, even to the point that a wide range of repairs to underwater structures and valves can be performed. Today, there are an increasing number of tools available for deciding what data to collect and safer and more efficient ways of gathering it. Data analysis and use of machine learning and AI is the next step. Using the example of the large number of ultrasonic thickness readings taken on pressure systems and structures, the RBI strategy can identify where to look, and how frequently, with many thousands of readings gathered. The basic current analytical approach is limited to looking for thickness readings with the guidance of codes such as API. Other readings that indicate that the thickness is ‘within limits’ are filed or discarded, even though the data contains highly valuable information that could help reduce risk, cost, and assist trend assessments and planning. One solution, designed for pressure system thickness inspection data, is a software programme called ANALYSE (PSI)™ which uses algorithms developed with a leading London university to statistically decide what data is needed to achieve a desired level of confidence. The software is then fed back actual data to confirm the condition of the equipment inspected. This has been applied fleetwide for a major operator and has now extended to a number of pilot programmes for other operators, with clear demonstrations of cost benefits in excess of 50% savings. ANALYSE has been further developed so that other data sets can be analysed; for example, visual data gathered by robotic cameras as well as synchronous laser thickness and distortion data on structures. The visual data is a target for developing machine learning capabilities, whereby computers can be taught to recognise and measure anomalies such as coating damage. The question of using machine learning to interrogate images is vital – scanning hours of video footage or images is not a productive job for humans and introduces the potential for loss of attention and errors.
Computers however, are difficult to ‘train’, with much time and effort required to teach them even basic image recognition, a task which humans can carry out almost instinctively. Many software security systems use humans’ ability to readily recognise objects and images to make sure robotic systems cannot access systems designed for human access only.
Can laser data be analysed by machines?
Figure 5 shows images digitised and designed for machine analysis. It is quite simple for a computer to identify any areas of distortion outside of a predetermined limit or changes in a distortion pattern over time or with different loading conditions. The NoMan laser data provides clear indications of corrosion and coating breakdown which can be verified by the visual data, both using machines taught to recognise and measure the level of damage. Statistical analysis of the data also reveals much more than the traditional approach of seeking the thinnest readings taken and discarding the remaining 90%. Algorithms developed with a leading London university are being widely used to determine the minimum thickness with known levels of confidence, even though the minimum measurements were not detected or recorded. This type of analysis also guides how many readings are needed to achieve the required confidence levels based on statistical analysis of historic data. The ANALYSE system has been proven to save over 50% of the data collection cost, as shown by a few of the case studies summarised below.
Figure 4. Machine learning on corroded structure.
Figure 5. Laser distortion scan.
Case studies: Pressure system inspection
Recent projects applying ANALYSE to pressure system inspections have already shown savings as follows: On an FPSO in Malaysia, UTM (Ultrasonic Thickness Measurements) were reduced from 2819 conventional UTMs to 1444 ANALYSE readings, producing a 49% saving. On an FPSO in Australia, UTMs were reduced from 210 conventional UTM readings to 78 ANALYSE readings producing a 60% saving. On a semisubmersible platform in the GOM (Gulf of Mexico), UTMs were reduced from 1056 to 258 ANALYSE readings, producing a 76% saving. On a semisubmersible in the GOM, 17799 conventional UTMs were reduced to 8807 ANALYSE readings producing a 51% saving. On an FPSO in Brazil, 393 conventional UTMs were reduced to 90 ANALYSE readings producing a saving of 77%. On a processing hub in Australia, 4546 conventional UTMs were reduced to 972 ANALYSE readings, producing a saving of 79%. A supermajor in the GOM saw reductions of over 50% achieved across a whole field.
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Figure 6. ANALYSE curve pointing to probable minimums with % confidence.
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The average saving was proven to be over 50%, with a further benefit of a quantified level of confidence in the reliability of the data which was set in accordance with industry guidelines. Data analysis and AI combined with an RBI strategy and robotic data collection systems could be the future of asset integrity management in the oil and gas industry.
Figure 7. ANALYSE graph with alarm levels and predicted minimum
thickness.
Summer 2022 Oilfield Technology | 35
When Man Meets Machine Philippe Herve, SparkCognition, USA, considers the uses of AI in the upstream oil and gas sector and discusses its role in performance optimisation.
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T
he strategic goals that characterise the global oil and gas industry have always been a moving target, albeit with relatively long time horizons. Throughout its 120-year history,1 the industry has also been at least somewhat at the mercy of various exogenous factors, ranging from geopolitics to energy prices, to environmental/climate-related forces. However, there are a few aspects of life in the oil patch that have not changed much in the industry’s long history, most notably the large capital investments required and the need to earn rates of return which commensurate with those investments. All that said, the industry, like all industries, is also at the mercy of the revenue and profitability expectations of markets and shareholders. A significant driver of this profitability is operating costs, driven largely by the need to maintain and repair all of the equipment required to conduct upstream E&P operations, whether offshore or onshore. Historically, the industry has relied upon the expertise of long-serving engineers and technicians to identify and perform needed maintenance, however it has become increasingly apparent in the past two decades that the sheer volume of available asset performance data is making this reliance on human expertise, with all its inherent biases and potential for errors, less and less tenable. This is where artificial intelligence (AI) and machine learning (ML) truly demonstrate their value. AI processes immense quantities of structured and unstructured performance data on complex technological assets and then applies ML algorithms to predict with remarkable accuracy when these assets will require maintenance, when they are approaching failure, or even
when their sub-par performance risks compromising the company’s decarbonisation/net-zero objectives. This level of insight provides asset managers and maintenance staff with advance notice that can turn a catastrophic equipment failure (for both workers and hardware) into a routine and much less expensive maintenance task. Oil and gas assets that operate at suboptimal levels not only undergo more frequent failures (contributing to the non-productive time (NPT) currently estimated to constitute 10% of total platform time), they also run less efficiently day-to-day, producing less oil and gas, generating less revenue, and exposing the company to potentially significant regulatory and compliance costs. Ensuring efficient, safe, and reliable E&P operations is thus both a top-and bottom-line challenge. Modern E&P systems provide second-by-second data on pump pressures, voltages, flow rates, emissions, and numerous other measures. AI systems, in turn, analyse all this data with ML algorithms and provide advance notice of equipment that needs maintenance or is nearing outright failure. Often though, data on complete system failure is unavailable because operators rarely let their assets run to the point of total failure. Nevertheless, ML capabilities are adept at predicting these failures and maximising the effectiveness of system operations. Several specific examples of SparkCognition’s work in the upstream oil and gas arena demonstrate the impact that AI and ML can have on reducing maintenance, forecasting and preventing failures, providing a safe, healthy work environment, and dramatically improving profitability and sustainability.
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Predictive maintenance
A global oil and gas supermajor determined that improving fleetwide platform availability by just 1% would accelerate oil production by millions of barrels per day, while reducing operating costs through predictive analytics and reducing the emissions produced by each asset. In addition, such a programme would significantly improve safety for the engineers and operators working on offshore platforms. The company undertook an evaluation of SparkCognition’s AI-based model-building capabilities that included a proof-of-concept exercise in which an initial blind data set was submitted for the separator system on one of their larger platforms. This separator system had a history of unexpected failures in multiple glycol systems and export compressors, contributing to about 80% of the downtime on that platform. Leveraging two to three years of historical data for each subsystem, SparkCognition developed models that correctly predicted 75% of the historical failures with an average of nine days advance forewarning. This proof of concept exceeded the company’s success criteria for the pilot and proved the viability of the modelling approach. The next stage of the project sought to operationalise the models at scale in a real-world production environment by developing data pipelines for both modelling and live execution as well as creating new models that provided alerts with fewer false positives and a greater degree of precision. Once deployed across the entire fleet of offshore platforms, the SparkCognition solution is expected to contribute significantly to the company’s net-zero strategy and reduce annual operating costs by US$10 – US$50 million, while also augmenting the group’s production by at least 5 million bpy.
Stuck-pipe prevention
A stuck-pipe event, in which the drill string can neither progress into the hole nor be removed from it, represents one of the most costly problems encountered in E&P work and is a significant contributor to non-productive time. It is thus crucial to predict and prevent such high-cost events from occurring whenever possible. Historically, physics-based approaches have been used to address the problem, but with only limited effectiveness. Predictive analytic techniques apply ML algorithms to historical sensor data from above- and below-ground assets used in drilling operations to construct a benchmark model of normal operations. This normal behaviour model is then used to evaluate sensor data in real time, identifying any values that deviate from established norms. These out-of-normal values indicate anomalous conditions likely to precede an impending stuck-pipe event. Not only does this approach enable operators to monitor the overall health of the drilling operation, it also gives drilling engineers and crews the extra time they need to proactively address and prevent the impending stuck-pipe event from taking place. Working with a large operator in the Middle East, SparkCognition deployed ML-based models across seven sites, predicting 79% of drilling anomalies, including stuck-pipe events, with up to six hours advance notice, providing the company with substantial cost savings in annual downtime. By detecting anomalies that predict stuck-pipe occurrences in advance, operators can not only better plan for or even avert these expensive events, they can also mitigate drilling dysfunction, enhance worker safety, and optimise drilling operations. These outcomes are described in more detail in the peer-reviewed technical paper: ‘Application of Artificial Intelligence and Machine Learning to Detect Drilling Anomalies Leading to Stuck Pipe Incidents.’2
38 | Oilfield Technology Summer 2022
Health and safety optimisation
Diligent safety and health oversight is a key contributor to staff productivity and overall organisation performance. Contributing to the health and safety challenge is the need to obtain actionable insights from the enormous quantity of data provided by historical incident reports. These records are regularly analysed for regulatory purposes, but usually through manual data entry. However, some safety managers are now using AI technology to take a more proactive approach to health and safety practices. These technologies enable safety personnel to quickly and efficiently glean insights from the free-form data found in incident reports and other documents. This capability then allows managers to forecast and avoid incidents before they occur. SparkCognition worked with a large oil and gas supermajor to implement its AI-based IRIS system to manage its health, safety, and environmental (HSE) risk assessment. Historically, thousands of risk assessments have been conducted each year for large oil and gas producers and refineries by filling a room with subject matter experts (SMEs). These experts then spend days assessing each risk and its potential consequences based on their own workplace experiences, which vary with each individual’s tenure and breadth of experience. As long-tenured engineers and technicians depart the workforce and the scale of available system data increases rapidly, this approach to risk assessment has become increasingly untenable. The IRIS system, on the other hand, employs a rigorous ML-based methodology in which risk probabilities and consequences are automatically analysed based not only on the specific facility or asset being assessed, but across a company’s entire portfolio of assets and locations, maximising the base of experience from which to draw insights into hazardous conditions and scenarios, both known and potential. The system calculates hazard likelihoods as well as consequence levels and probabilities, then identifies targeted safeguards and risk mitigation actions that can significantly reduce, or even eliminate, the identified risks. This approach makes the most efficient use of the company’s entire base of HSE experience and information, providing a safer work environment and also serving as an effective platform for transferring valuable safety and risk information to new staff members.
Conclusion
A recent McKinsey & Company report estimated that offshore oil platforms are, on average, running at only 77% of maximum production potential, representing as much as US$200 billion in annual lost revenue.3 Many factors contribute to suboptimal operational, environmental, and financial performance in the upstream oil and gas arena. There are now a number of case studies suggesting that the next step in the evolution of the industry will be built on the rigorous use of artificial intelligence technologies such as machine learning. These technologies increase the effectiveness of decarbonisation programmes and enable companies to realise the maximum efficiency from their expensive assets, leveraging to a far greater extent the vast quantities of sensor data available on surface assets, as well as that buried deep underground.
References 1. 2.
3.
KOROTEEV, D., AND TEKIC, Z. Artificial intelligence in oil and gas upstream: trends, challenges, and scenarios for the future, Energy and AI, (March 2021). BIMASTIANTO, P. A., KHAMBETE, S. P., ALSAADI, H.M., AL AMERI, S. M., COUZIGOU, E., AL-MARZOUQI, A.R., AL AMERI, F. S., ABOULABAN, S., KHATER, H., AND HERVE, P., ‘Application of Artificial Intelligence and Machine Learning to Detect Drilling Anomalies Leading to Stuck Pipe Incidents,’ paper presented at the Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, UAE, SPE-207987-MS, (November 2021). BRUN, A., TRENCH, M., VERMAAT, T. Why oil and gas companies must act on analytics, McKinsey & Company, (October 2017).
Dr. Bruno Pinguet, TÜV SÜD National Engineering Laboratory, UK, outlines how uncertainty analysis can help determine the capabilities of flow measurement systems in meeting their required performance targets.
To flow or not to flow W
ithin the oil and gas industry, it is commonly believed that the most accurate flow rate measurements are from the separator. From a technical point of view, with enough residence time, a great enough contrast of density among the phases, and the use of an enormous production separator, it is possible to obtain high accuracy in line conditions. Unfortunately, for practical and cost reasons, such as mobility on the road or lifting with cranes, and the need for ruggedised equipment for shocks and vibrations, a production test separator is unlikely to be used.
However, the alternative smaller and more commonly used well test separator often does not meet expectations. Some rules have therefore been established to enhance the overall performance of well test separators, such as a consensus on the minimum residence time of around one minute. In recent years, a large number of devices have been added inside the test separator to reduce turbulence, facilitate coalescence, and reduce carryover with some demisting devices. Another restriction of the test separator is that the fluid coming out of each single-phase line must at all
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times remain in the relevant range of the single-phase meter being used as a reference on the gas line, such as a multiple set of orifice plates or Coriolis flow meters following the expected flow rates. The same series of devices are also necessary on the liquid line with multiple positive displacements, turbines, or Coriolis of various sizes. The list is not exhaustive but shows the number of devices that are required to maintain nominal conditions for accurate measurement, even if the separation is optimal.
Multiphase flowmeters
Multiphase flow meters (MFMs) have been employed as complex measurement systems in the oil and gas sector for many years. As they can eliminate the need for a test separator, which is difficult to maintain, smaller platforms are possible. Existing facilities can also be upgraded to take subsea tiebacks without having to add an extra test separator. MFMs also give continuous measurements, allowing better reservoir management, well optimisation, and a quick response to water break-through and similar events. As MFMs are becoming drastically cheaper, most oil and gas operators could now take advantage of their use. However, while they reduce CAPEX, fundamental questions remain over the reliability and capability of such equipment to perform accurately when compared to previously used systems. This is because the claimed theoretical uncertainty of meter manufacturers does not always match that of a more conventional test separator setup, making some oil and gas companies question their accuracy in service. The buying process therefore very often involves some comparison tests being made either before delivery, later in the field on a regular basis, or as a spot-check against standard equipment, such as separators. While flow meters are calibrated under ideal laboratory conditions, the environments into which they are installed vary greatly. In the oil and gas industry however, many flow measurement systems are reporting flow rates without much consideration towards measurement uncertainty. Uncertainty analysis is therefore essential to determine whether measurement systems are capable of meeting required performance targets.
What is uncertainty?
It is a misconception that measurement is an exact science. All measurements are merely estimates of the true value being measured and the true value can never be known. The terms ‘accuracy’ and ‘uncertainty’ are also misused in the oil and gas industry. Accuracy refers to the agreement between a measurement and an expected true value. Therefore, accuracy requires two measurements with two different meters. Accuracy cannot be discussed meaningfully unless the true value or most probable value is known or can be recognisable. On the other hand, uncertainty is an interval defined around the average which is based on the data collected over a given period that is considered a stable flow condition. The true value can be expected to be within the confidence level inside the interval defined during the measurement. The size of the interval is described as a confidence interval or in terms of sigma (i.e., standard deviation from a statistical point of view). To make MFMs easily comparable and effectively report their performance, the multiphase flow metering community has decided to follow the 95% confidence level or 1.960 multiplied by one sigma. From a practical point of view, this means that when a measurement is made repetitively (under continuous stable flow), then a standard deviation can be calculated using the numerous collected data. This is defined as 1 sigma (σ) which means that there is a 68% chance that the true value is within this interval. This standard deviation ‘σ’ is multiplied by 1.960 and provides the performance or uncertainty interval with a 95% confidence interval (Figure 1).
Uncertainty elements
So, how can operators effectively allow for this uncertainty? The ideal approach would be to calibrate each individual device for the specific conditions it will encounter. However, this is not financially realistic and to establish the performance of an MFM, an uncertainty budget must therefore be constructed, taking into account additional uncertainties arising from interpolation and extrapolation from calibration conditions. Firstly, calibration against a single-phase meter at least three to four times better than the device in question is needed. This is done in a third-party flow loop facility, the best being a primary calibration facility. Secondly, the repeatability performance of the MFM must be 68.3% established. The repeatability of the device-under-test (effectively the closeness of agreement between successive measurements made under the same conditions) 95.4% is in its estimation of the overall 34.1% 34.1% uncertainty of the calibration. 99.7% The repeatability is demonstrated by maintaining the flow conditions 2.1% 2.1% 0.1% 0.1% of operation and simply 13.6% 13.6% switching the device off and on. Any possible deviation that -3σ -2σ -1σ μ 1σ 2σ 3σ appears will need to be taken into account as repeatability. 800 bopd 1,000 bopd 1,200 bopd Reproducibility is another Figure 1. Normal or Z-distribution with the associated confidence level. essential parameter from the
40 | Oilfield Technology Summer 2022
end user’s point of view. This is established by moving from a given condition, such as pressure or choke opening, etc., to different conditions and then returning to the previously given conditions. Meter drift is a systematic uncertainty that should also be accounted for, as this determines how the error in the measurement process will change over time. Bias is very well documented and addressed in ISO 21748 and it could also be a source of uncertainty. Stability is another parameter to consider, as if there have been multiple calibrations of the same flow meters over the years, this will be the standard deviation of the calibration results. The standard uncertainty and the associated stability of the reference measurement should also be taken into consideration.
Ensuring a proper comparison
To establish the performance of an installed MFM against a reference flow meter, some prerequisites are necessary. For example: Both devices must be as physically close as possible so changes between them in line pressure and temperature are minimal. Both devices must record data at the same time. Both devices must use the same pressure-volume-temperature (PVT) package to perform the conversion from line to standard conditions, or from the MFM conditions to reference flow meter conditions. If the devices are not close to each other, the cumulative volume measured must be three times larger than the storage volume between both flow meters. It is important to remember that the longer the recording, the more accurate the established uncertainty of both devices will be. If the devices are far away and the flow reaches the MFM long before the other device, then the reference flow meter
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ÌÌ ÌÌ ÌÌ ÌÌ
recording time should be defined to capture the same type of flow passing through both meters. No choking should occur between both devices to keep the PVT package consistent and for the quick evaluation of the line or standard conditions of both devices. Both devices should be within the sweet spot of their working envelope. Both devices should be set with the relevant intrinsic fluid properties package, or equations of state (EOS) to ensure proper calculations. The reference flow meter’s transmitters or sensors should be within the specification and zero-trimmed or corrected for deviation to account for any potential bias.
Having spent nearly 30 years researching and developing multiphase flow meters, TÜV SÜD understands the commercial benefits MFMs can deliver. However, their acceptance within the conservative oil and gas sector is slow, with over 10 000 units having been sold by approximately 20 manufacturers today. The company estimates that this represents over 95% of the total market. To ensure the validity of an MFM’s measurements, comparison tests should be conducted either during the buying process, before delivery, or later if results do not match client expectation or reservoir model forecasts. Validation of test comparisons in well-controlled conditions can therefore be achieved by a third-party that is familiar with field well test operations. This helps to avoid any conflict about who is right or wrong and provides a clear final statement based on statistical analysis, physics, and field expertise.
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Go with the flow A
s the global energy mix transitions to low-carbon sources, there may be fewer opportunities for new oil and gas field developments. As a result, many operators will shift their focus towards recovering more from existing reservoirs, and this strategy includes improving the management and performance of their horizontal wells. Horizontal wells generally deliver much higher levels of productivity than their vertical counterparts, but this performance can often come at a cost. Understanding the interactions between a horizontal well and the reservoir can be extremely challenging. The combination of variable well angles, extended reservoir contacts, the presence of fluid mixtures and segregated flows, formation changes, fractures and intricate completions presents a formidable challenge for analysis using conventional production-logging tools (Figure 1). Standard production-logging technology may, under some conditions, be able to map the multiphase flows encountered in a horizontal wellbore, but it cannot quantify flows for fluids exiting or entering the reservoir behind the completion. This means that wellbore production logs do
42 |
not provide a complete picture of flow dynamics across the well system. Asset teams that base development, production or remediation plans on an incomplete partial flow diagnosis may be risking lower productivity, reduced asset performance, and a higher carbon overhead.
A new beginning
Reservoir and production engineers have been looking to overcome the drawbacks of conventional production surveys in horizontal wells for many years. Their key requirement has been a system that could deliver continuous flow profiles across different completion and reservoir scenarios, and would also be effective in reservoirs with fractured formations. TGT Diagnostics has been working on addressing these needs for several years and, in February 2022, launched the Horizontal Flow diagnostics product with Cascade3 technology. Specifically designed for horizontal wells, this system offers more realistic flow modelling and accurate continuous flow profiles in a wide variety of completion and reservoir settings. The insights gained from this have the potential to
Ken Feather, TGT Diagnostics, UAE, describes a new approach to flow diagnostics in horizontal wells.
help companies reduce operating costs and energy consumption while increasing ultimate recovery. The new technology uses an advanced modelling and simulation engine to predict the hydrodynamic and thermodynamic behaviour of fluids and their surroundings as they flow through the well–reservoir system. This translates temperature, pressure and other well-system data into continuous reservoir flow profiles. These profiles deliver a true picture of inflow and outflow, and this is the case even for challenging wells and those that feature natural or hydraulically induced fractures. The ability to assess flow in fractured reservoirs is important because, although fractures can boost hydrocarbon production, they can also provide pathways for early water or gas breakthrough. The new diagnostics technology can evaluate the radial, spherical and linear/fracture flow patterns commonly encountered in horizontal well systems (Figure 2). This provides an accurate assessment of the linear flow occurring in the fractures and makes it possible to determine the fracture contribution. This is particularly useful when combined with the
Chorus acoustic sensing system that identifies fracture locations along the wellbore.
Applications and benefits
Operating companies want to maximise hydrocarbon recovery in the safest, cleanest and most economical way possible. Having an accurate picture of fluid flow in the wellbore and the immediately surrounding reservoir rocks gives asset teams greater confidence in their decisions and makes it easier to enhance production, maximise recovery and rectify well problems. The new diagnostics system provides useful input in key areas such as reservoir, well and resource management, and can even help companies enhance their environmental performance and reduce the carbon footprint of production operations.
Insights for reservoir management
Effective reservoir management is a key objective for oil and gas operating companies. The development of any hydrocarbon reservoir disturbs a
| 43
natural balance of rocks and fluids that may have existed for millions of years. Understanding how a reservoir will behave as new wells are drilled and fluids are extracted or injected is a daunting task. Reservoir engineers deal with huge uncertainties in their quest to maximise hydrocarbon recovery, reduce operating costs and extend the economic life of the reservoir. At the heart of the reservoir-management process is the dynamic reservoir model, which provides a basis for all field development and hydrocarbon recovery decisions, infrastructure investments and reserves estimations. The robustness and accuracy of the model is critical to successful reservoir management, and any inaccuracies may lead to poor decisions and substantial losses. As more data is collected, the dynamic reservoir model is updated by the reservoir engineering team using a process known as history matching. Insights from this new diagnostic system can play a critical role in history-matching, thus helping to reduce the uncertainty envelope and improve the model. A continuous flow profile provides a clear and direct
quantification of the flow performance of the reservoir as it feeds the well system. In contrast to standard wellbore production surveys, which can be hindered by completion or reservoir integrity issues, Horizontal Flow can deliver a true flow profile. The continuous nature and sensitivity to low flow rates help provide a more accurate measurement of effective pay length, a key metric for making production forecasts and reserves estimates. The new system is also effective in the presence of fractures. Predicting and preventing water or gas breakthrough is one of the most important and challenging tasks faced by reservoir engineers. Having a deeper understanding of downhole flow dynamics can help provide an early warning of the locations where water or unwanted gas may be reaching the well. The new workflow can also be used to estimate or validate other key parameters such as reservoir pressure, permeability and skin factor. This independent verification can help reservoir engineers to resolve uncertainties, improve history matching and optimise the dynamic reservoir model.
A diagnostic approach to well management
Figure 1. Horizontal Flow leverages Cascade3 and the True Flow system to deliver the truest picture of inflow and outflow downhole, even in the most challenging wells.
Figure 2. Flow inside the wellbore of a horizontal well can be challenging to decipher, but flow in the surrounding reservoir is equally complex. New technologies can help resolve all three primary flow patterns that surround the well system – radial, spherical and linear flow in fractures – and combines thermodynamic and hydrodynamic science in an immersive 3D fine grid modelling architecture. The result is accurate reservoir flow profiles and unique insights that help asset teams keep performance on track.
44 | Oilfield Technology Summer 2022
Horizontal wells are designed to provide optimum contact with the reservoir and so tap hydrocarbon reserves with maximum efficiency. Production engineers and the wider asset team are responsible for the well system and ensuring that it performs to expectations, thereby maintaining production targets and maximising recovery. Well performance depends on the dynamic relationship between the well completion and the reservoir surrounding it. This, in turn, depends on the performance and behaviour of completion components and the reservoir itself. To achieve their technical and business aims, production engineers need full visibility of fluids and flow dynamics downhole from the reservoir sandface to the wellbore and at all points in between. The Horizontal Flow diagnostics system helps to deliver this visibility. Measuring real production or injection performance in the presence of complex multicomponent completions is a major challenge for production engineers. Integrity issues and zonal isolation or component failures can lead to discrepancies between the profile of fluids entering or exiting the wellbore and the profile of fluids exiting or entering the reservoir. In these situations, standard production logs could give false or misleading results. The new diagnostics system overcomes this by providing a definitive flow profile regardless of completion, integrity or zonal isolation issues. Furthermore, by identifying these issues, it can help guide maintenance or workover interventions. Viscous fluids, fluid segregation and low flow rates can also be problematic for standard production-logging sensors, leading to a false picture of flow. Horizontal Flow incorporates temperature and acoustic measurements that respond to all types of meaningful flow, thereby helping to overcome this limitation. The new approach can also be used to assess injection compliance and the performance of
completion elements such as inflow control devices and swell packers. The information gained from these analyses can be used to target repairs and guide potential improvements in completion designs.
Enabling effective resource management
Operating companies want to maximise ultimate recovery while minimising operating costs, thereby reducing cost per barrel produced. Horizontal Flow diagnostics can help on both sides of this equation. Developing a field with horizontal wells represents a significant investment in time, energy and capital. Diagnostics play a key role in tracking well and reservoir performance, and steering asset team decisions. Horizontal Flow diagnostics can reveal well system inefficiencies, guide asset teams to problem areas in the completion or the reservoir, and help them act with greater certainty to achieve a positive outcome. Horizontal well interventions can be expensive and time-consuming, and often require specialised equipment, such as coiled tubing or tractors, for well access. Diagnostic deployments of the new system can provide a complete and accurate downhole assessment and information that reduces uncertainty and quickly establishes whether remedial work is required. When a workover is deemed necessary, the ability to plan and target it with greater precision helps save time, reduce costs and deliver better outcomes.
can minimise this overhead on two fronts when compared with a conventional approach. Firstly, it can easily identify the crossflows, fractures and integrity failures that often confuse conventional surveys. Having this information minimises the risk of incomplete or inaccurate assessments, and improves the efficiency of decision-making. Secondly, when equipped with reliable information, the asset team can plan and target its workover programmes with precision. This means equipment and operations can be optimised and executed with higher efficiency and success rates, leading to better technical outcomes and lower emissions.
Conclusion
Horizontal wells are powerful tools for hydrocarbon production and represent a significant resource investment for field operators. Production engineers, reservoir engineers and the wider asset team face complex challenges in their drive to ensure that each well system performs to expectations. A new approach to flow analysis in horizontal wells could help to solve key challenges in this area, making it easier for wells and reservoirs to reach their full potential.
References 1.
Rystad Energy, EmissionsCube.
Reducing your environmental impact
Operating companies around the world are Case Study aiming to cut their carbon-per-barrel overhead. Challenge Developing and producing oil and gas consumes Low-permeability oil rim reservoirs can be developed using horizontal wells and multistage fractures. enormous amounts of energy from diesel The challenge for operators is to find a hydraulic fracture design that improves production while minimising the risk of gas or water breakthrough from adjacent formations. engines or gas turbines, both of which produce Fluid breakthrough harms well economics and can lead to significant environmental impacts, for example, significant volumes of carbon dioxide (CO2). through the need for gas flaring. Predicting and preventing water or gas breakthrough is one of the most important tasks faced by Flaring of unwanted associated gas is another reservoir engineers. major source of emissions. Combined CO2 Operators will typically use pressure transient analysis to assess fracture sweep efficiency, but this provides only average fracture parameters. A deeper understanding of downhole flow dynamics can provide an early emissions from global upstream operations warning of the locations where water or unwanted gas is reaching the well. A horizontal well had been are estimated at about 1 Gt CO2 per year and drilled into the oil rim of a low-permeability reservoir formation and hydraulically fractured in 12 stages. The methane emissions at around 1.9 Gt CO2e per year.1 gas/oil ratio for the well was high, indicating a potential issue with the fracture design that would need to be addressed before delivering or completing further wells in the field. New diagnostics technology can help operators identify inefficiencies in energy-intensive Result The Horizontal Flow survey identified three gas breakthrough zones responsible for the well’s high gas/oil ratio operations, reduce associated gas and estimated potential fracture growth, thereby indicating how far the fractures penetrated into the overlying flaring and improve the efficiency of energygas-bearing formation. Fracture entry points behind the liner were assessed using the Chorus platform. This also revealed fractures in the target oil-bearing formation that were idle or nonproductive, owing to the intensive intervention operations. gas breakthrough. Water injection accounts for approximately In this well, the completion contained swellable packers, which meant that gas producing zones could be mechanically shut off. For future wells, the operator has redesigned the fracture programme so that production 40% of total CO2 emissions in a typical oilfield. from the low-permeability oil rim can be maximised while preventing gas breakthroughs caused by out-of-zone Operators can now assess how much of the fractures. Reducing the fracture pressure was identified as the most effective way to achieve this. injected water is reaching its target and identify thief zones. These diagnostic surveys often lead to a reduction in pumped water volumes and emissions, and increased field production. Water production is another source of emissions, as produced water must be managed and treated at the surface. This process requires energy, and increased water production typically means less oil, thus reducing ultimate recovery and increasing carbon per barrel. Gas flaring is estimated to release 310 MT CO2 per year, which is about 30% of all upstream CO2 emissions. Continuous flow profiles can be used to identify sources of unwanted gas downhole and guide remediation plans, thereby reducing the need to flare. Workovers and diagnostic interventions in horizontal wells can also have a significant Figure 3. Horizontal Flow leverages Cascade3 and the True Flow system to deliver a true picture of carbon overhead. New diagnostics technology inflow and outflow downhole, even in challenging wells.
Summer 2022 Oilfield Technology | 45
COMBATTING CORROSION AND DEPOSITION Ana Ferrer, Ph.D. USA, and Brian Bennett, ChampionX, UK, discuss the importance of combatting iron sulfide deposits and scale in flowlines and water processing systems.
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I
n oil and gas production, and particularly in ageing assets, deposition in flowlines and water processing systems is a common and costly problem. Deposition consists of a variety of different components but is usually a combination of hydrocarbon carryover, iron sulfide (FeS), biomass, inorganic scale, and/or sand.1 The formation and build-up of FeS and/or inorganic scale can result in loss of production due to issues such as plugging, corrosion, flow restriction and emulsions. Finding efficient ways to handle oil-wet solids is a challenge. Chemical scale inhibitors, Tetrakis (hydroxymethyl) phosphonium sulfate (THPS) or acids can be very corrosive and have historically been used for remediation purposes to remove FeS scale from oil and gas wells. However, they have not always been found to be the most effective solution, and their use could potentially lead to a variety of additional problems, such as hydrogen sulfide generation. ChampionX has developed a portfolio of products that act as cleaners, corrosion inhibitors, iron sulfide dissolvers and scale inhibitors. These products have low corrosivity, even in neat form, and are effective not only in the laboratory but also in several
different field applications, including saltwater disposal (SWD) operations, where remediation of iron sulfide deposits, inhibition of scale formation, and minimisation of corrosion is needed.
Challenges surrounding THPS chemistry
Once deposition has formed in a system, it can be removed by mechanical or chemical means. Mechanical methods can be expensive, and some systems may not be fully accessible due to lack of pigging capability. As a result, chemical remediation is sometimes the only option. It is also a lower-cost option when manual removal, downtime, and the risk of potential exposure to cleanout debris is considered. A common oilfield biocide, THPS, is known to remove FeS scale from oil and gas wells.2 While it is effective at dissolving FeS by chelation, it poses challenges related to low pH, especially if the injection system is carbon steel. While THPS can be detrimental to the injection system,3 once it is injected, it is not usually harmful to production equipment due to its dilution with the production fluids. However, a product containing THPS in neat form can be problematic if the available injection option is carbon steel.
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Chemicals
Chemistry
FeS Dissolvers FesD-1
75% THPS in water.
FesD-2
99% new FeS dissolver in water.
P-1 to P-23
Alternative FeS dissolving actives/chemistries in water.
Finished Products
FP-1
THPS + Proprietary surfactant package-based product (pH – 3).
FP-2
New FeS dissolver + quat based product (pH – 9).
FP-3
New FeS dissolver + proprietary surfactant package-based product (pH – 7).
TCFP-1
Triple combo (FeS + CI + SI) – THPS + proprietary surfactant package + phosphonate-based SI.
TCFP-2
Triple combo (FeS + CI + SI) – New FeS dissolver + proprietary surfactant package + phosphonate-polymer based SI.
TCFP-3
Triple combo (FeS + CI + SI) – New FeS dissolver + proprietary surfactant package + polymer-based SI.
TCFP-4
Triple combo (FeS + CI + SI) – New FeS dissolver + proprietary surfactant package + phosphonate-based SI.
Table 1. Chemicals and the corresponding chemistry used in the experiments.
With the potential presence of other inorganic scales, such as calcite and barite, THPS may not be as effective. Specific inorganic scale inhibitors must be employed to remediate these types of deposition.
Experimental studies
The initial intent of ChampionX’s research was to determine if an alternative FeS-dissolving active could be identified that had the equivalent – or better – performance to THPS but did not pose the corrosivity issues with carbon steel. All the chemicals used in the study are listed in Table 1. The series of tests described in the article were carried out to compare FeS dissolution, corrosivity, corrosion inhibitor performance and scale inhibition.
FeS dissolution test A screening test methodology was performed to evaluate the alternative chemistries to the incumbent chemistry (THPS). Once the new alternative to THPS for FeS remediation was identified (referred to as the new FeS dissolver), formulations containing the active and THPS, as well as the proprietary cleaner/corrosion inhibitor package, were developed. The efficiency of both FeS dissolvers (THPS versus the new FeS dissolver) at dissolving FeS deposits was qualitatively and quantitatively assessed using a series of static bottle tests.
Corrosivity and corrosion inhibition studies Multi-functional formulations containing the FeS dissolver (THPS and the new alternative), cleaner/corrosion inhibitor package and scale inhibitor were also developed (TCFP-1 to TCFP-4). The ability of these formulations to partition through an oil phase into a water phase under stagnant, or low, mixing conditions was assessed by the LPR bubble cell testing. Working electrodes used in these corrosion tests were made of steel grade 080A15 (mild steel C1018) and had an approximate area of 4.75 cm.2
Scale inhibition testing Dynamic Scale Loop (DSL) and barite static bottle testing were used to evaluate the scale inhibition performance of the multi-functional formulations by determining their minimum effective dosage (MED). DSL was performed at 93°C (200°F) and 1000 psi for this study, whereas barite bottle testing was carried out at room temperature 23°C (75°F) and atmospheric pressure. The pass criterion for MED in the barite bottle test is greater than 80% scale inhibitor efficiency. However, this is dependent on test temperature and brine composition.
Results
Figure 1. Bubble cell test results for the four multi-functional products.
48 | Oilfield Technology Summer 2022
A full analysis of the procedures and the results across each test scenario are detailed in the Society of Petroleum Engineers paper, IPTC-22249-MS.4 In summary, regarding the FeS dissolution test, all quantitative results suggest that FP-2, and, more specifically, the new FeS dissolver is more efficient than FP-1 (THPS-based product) at dissolving iron sulfide by complexing the iron. Most notably, THPS has proven to be less efficient at dissolving FeS at a pH higher than six.5 Further testing would be required to determine the stoichiometry ratio between the chelating agents (THPS/new FeS dissolver) and the iron sulfide. Dissolving FeS was the primary goal in this project, but equally as important was identifying an alternative that would be less corrosive to mild steel when formulated into a product.
The active FeS dissolvers were evaluated individually and the new FeS dissolver was found to be non-corrosive to mild steel at elevated dosages. Once formulated into the finished product, the corrosion inhibition was tested and shown in Figure 1, which provides a visual representation of the real-time corrosion rate in each test vessel before and after the four multi-functional products were injected. Aside from the untreated cell, the four datasets show an immediate drop in corrosion rates after injecting the products at the two-hour time point. This demonstrates the inhibitor’s ability to partition out of the hydrocarbon phase and film the metal surface in the water phase without the aid of mixing. When the TCFP-2 and TCFP-3 and TCFP-4 formulations were injected, the initial sharp decrease was then followed by a much more gradual decrease in corrosion rate over time. This likely means that the protective film was well established. During scale inhibition testing with the DSL apparatus, only the scale inhibitor packages were tested due to the potential surface-coating nature of the corrosion inhibitor component. Only two of the four products (TCFP-2 and TCFP-4) passed the DSL test at a 100 ppm dose rate but failed at 50 ppm, thereby giving a MED of 100 pm under these testing conditions. They are considered more suitable for calcite scale inhibition than TCFP-3, which had a MED of 200 ppm. The results of the static barite bottle tests performed at 23°C (75°F) indicate the scale inhibitor package present in TCFP-3 inhibited barite scale more efficiently under these testing conditions.
Over a four-month period, careful field observations were made to determine if the new treatment programme was working. A visible reduction in turbidity and opaqueness of the water in the tanks (Figure 4) can clearly be seen. Since the application of the multi-functional product, the tank level monitors have not failed due to FeS and calcite scaling. Notably, significant variability in the water sent to public SWDs can make treatment validation difficult with varying throughput and total filtered solids data. A further complication arises from the fact that performing iron sulfide performance testing in the field is difficult due to the presence of oxygen once the sample is collected.
Field evaluation
As proven in laboratory tests, a single, multi-functional product can remediate iron sulfide deposition, inhibit scale formation, and minimise corrosion. Scale and solid deposits were causing operational challenges for a major public operator carrying out SWD operations in the Midland and Delaware Basins in the US. This included tank level monitor fouling, filter fouling and downtime related to mechanical removal of solid deposits. The operator, who had relied on minimising solid build-up to maintain safe and economical produced water injection and disposal, was experiencing scale precipitation on their tank level monitoring probes at six of their saltwater injection facilities, causing major system issues (Figure 2). The most expensive and time-consuming issue was the rate at which the tank level monitors were failing. Once they failed, the system would need to be shut down for manual cleaning. Scale build-up was severe enough to require expensive mechanical removal every three to four weeks. In addition, the filter pods located before the high-pressure injection pumps had to be cleaned frequently. Solids collected from the probes were a combination of carbonate and iron sulfide scale with varying levels of organic proportions (Figure 3 and Table 2). While carbonate scaling tendencies from water analysis on the inlet were low, due to the large volume of water travelling through each facility, major scaling issues were still observed. Water collected from the inlet to the facility was dark grey and had low transmittance. A treatment upstream of the SWD with one of the novel, multi-functional products at a 35 ppm continuous dose rate was proposed with an additional treatment at the inlet. This formulation was also recommended as a standalone treatment at a dose rate of 25 ppm on the lines feeding the smaller facilities.
Figure 2. Facility diagram outlining pre-treatment issues.
Figure 3. Solid scale build-up on the probe.
Summer 2022 Oilfield Technology | 49
To prove product and programme performance analytically, both soluble and insoluble iron measurements were taken. Total and filtered iron were tracked during this new chemical application. Average soluble and insoluble iron collected at the largest SWD clearly showed an increasing trend in soluble iron and an overall decrease in the insoluble iron compared to the untreated sample. The recommended treatment of the multi-functional formulation in this SWD application was a success and provided: Safer, more effective day-to-day operations. Unfailing tank level probes since the application was started. Significantly improved water quality. Reduced facility downtime by not having to clean tank probes. Calculated average reduction of 5600 lbs. of insoluble iron per year.
precipitated in solution. Further studies revealed that when coupled with a scale inhibitor, whether for calcite or barite inhibition, the multi-functional products performed well in a series of lab tests, including LPR bubble cells for corrosion inhibition and DSL testing for scaling tendency. The performance was then verified in a field SWD application where there was visible solid deposition from produced water going into the system and causing failures of the tank level monitoring probes, necessitating regular full system shutdowns for manual cleaning. Continuous application of the multi-functional product containing the novel, non-corrosive iron sulfide dissolver eliminated the need for system shutdowns to clean the tank level monitors and reduced the frequency for filter changing. The water quality visibly improved, becoming clear and transparent. The soluble iron trends were reversed after the product was applied, indicating FeS was being dissolved. Overall, the method used to identify a multi-functional product to address iron sulfide and calcite scale was successful.
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Conclusions
Based on the lab results obtained in the ChampionX project, a non-THPS FeS alternative that was more compatible with carbon steel than THPS was identified. FeS dissolution testing showed it performed better than THPS at dissolving FeS once the FeS was
References 1.
SWD Unit 1 Largest
2
3
4
5
6
Xylene soluble organics (paraffin and asphaltenes)
1.8
7.7
15
39.4
57.3
46.9
Water soluble (salt)
6.7
3.2
4.7
3.8
11.2
11.2
Iron and calcium carbonates (acetic acid soluble)
76.9
55.1
54.5
29.2
14.5
9.8
Iron sulfide and oxide (HCI acid soluble)
13.8
29.6
23.6
25.8
15.8
29.5
HCI acid insoluble
0.8
4.4
2.2
1.8
1.2
2.6
Table 2. Solid analysis results (%) from scale collected at multiple facilities from the probes.
Figure 4. Summary of field observations and photos of water samples from the SWD tanks.
50 | Oilfield Technology Summer 2022
2.
3.
4.
5.
NASR-EL-DIN, H.A., and AL-HUMAIDAN, A.Y., ‘Iron Sulfide Scale: Formation, Removal and Prevention,’ paper presented at the International Symposium on Oil Field Scale, Aberdeen, Scotland, UK, SPE-68315-MS (January 2001). WYLDE, J. J., OKOCHA, C., SMITH, R., MAHMOUDKHANI, A., and KELLY, C. J., ‘Dissolution of Sulfide Scale: A Step Change With a Novel, High Performance, Non-Mineral Acid Chemical,’ paper presented at the SPE International Oilfield Scale Conference and Exhibition, Aberdeen, Scotland, UK, SPE-179880-MS (May 2016). CHEN T., WANG Q., CHANG F., and ALJEABAN N., ‘Recent Development and Remaining Challenges of Iron Sulfide Scale Mitigation in Sour Gas Wells,’ paper presented at the International Petroleum Technology Conference, Beijing, China, IPTC-19315-MS (March 2019). FERRER, A., and BENNETT, B., ‘Remediating Oilfield Deposition from the Laboratory Bench to the Field – Development of a Multifunctional Product,’ paper presented at the International Petroleum Technology Conference, Riyadh, Saudi Arabia, IPTC22249-MS (February 2022). AHMED. M., ONAWOLE.A., HUSSEIN.I., SAAD.M., MAHMOUD.M., and NIMIR.H., ‘Effect of pH on Dissolution of Iron Sulfide Scales Using THPS’, paper presented at the SPE International Conference on Oilfield Chemistry, Galveston, Texas, USA, SPE 193573-MS (April 2019).
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Ready for lift-off!
A
n Electrical Submersible Pump (ESP) is an effective and efficient artificial-lift method for extracting moderate to high volumes of fluids from wellbores. Commencing production from an offshore well equipped with an ESP is not a trivial task, but what is equally cumbersome is replacing a failed ESP. It is a high cost and time-consuming activity that can significantly affect production. Therefore, for offshore operators, the reliability and performance of artificial lift systems becomes paramount in mitigating the impact caused by unplanned interventions. With the digitalisation of
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oilfield operations and the subsequent increase in data availability from various instrumentation at the wellsite, digital platforms can play a pivotal role by providing valuable insights into dynamic operating and downhole conditions.
Remote monitoring and surveillance
Maximising the performance of an artificial lift system depends on the ability to manage the system’s operating parameters in real-time due to the dynamic nature of the reservoir, fluid properties, wellbore, and equipment condition. It requires a complete situational awareness of what has
happened in the past, what is happening now, and what might happen in the future. Combining data from disparate sources and deriving operational intelligence from it differentiates one production monitoring system from the other. The ProductionLink integrated production optimisation platform provides a condition-based monitoring solution with capability and interoperability for data aggregation, surveillance, and remote control of artificial lift systems. It provides a suite of descriptive and prescriptive analytics for easy and instantaneous identification of trends, patterns, and anomalies to diagnose
Anil Wadhwa, Baker Hughes, USA, considers how digital technology could help offshore operators maximise artificial lift system performance.
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pump and well conditions. This solution enables closed-loop control of variable speed drives and is compatible with all common data standards. Its integrated case management and
interactive automated reporting system make it an efficient and user-friendly surveillance system. Production engineers can track ESP performance and operating conditions by correlating a variety of downhole events and data from streaming feeds and historical data silos. This allows them to maximise pump operability with swift and precise actions resulting in minimal downtime while maximising a well’s production potential.
Advanced analytics
Figure 1. By bringing intelligence to the well site, Baker Hughes is leveraging automation by remotely controlling and optimising wells to maximise production.
ProductionLink Predictive Failure Analytics (PFA) is a technique for the early detection of operational events and anomalies in an ESP system to prevent costly failures. It utilises machine learning models built on historical data combined with knowledge-based methods and physics-based models to determine a cumulative effect on the overall system health. This is in contrast to traditional monitoring methods that employ threshold-based alarms to detect critical events after they have occurred. PFA goes deeper to detect and analyse critical events and anomalies in surface and downhole sensor data in real time. The data models are trained using sensor time-series data from past failures. These rely on advanced data processing, interpolation, quality evaluation, and feature engineering. The trained models are deployed to predict short-term damage events that may lead to immediate failures, such as a broken shaft, short-circuit, grounded downhole failure, and long-term events which build up over time, such as sand, scale deposition and efficiency degradation. The data-driven predictive failure analysis and engineered workflows help correlate downhole events with historical failures and estimate mean time-to-failure from other systems to reliably predict the remaining useful life (RUL) of an ESP, and better prioritise and plan well intervention and workover activities.
Edge computing Figure 2. Examples of edge IoT applications.
Figure 3. Leveraging digital technology to facilitate production asset management.
The ProductionLink Edge smart artificial lift automation controller provides an edge computing and IoT (Internet of things) framework to continuously monitor and analyse data from any artificial lift system. It provides the flexibility and interoperability to deploy Machine Learning and Artificial Intelligence-based analytics at the wellsite to automate decisions with precision and speed not possible with manual workflows. Its modular application framework supports different use cases by remotely deploying the appropriate software, reducing the need for different controller hardware to serve multiple applications. Its advanced communication protocol and cyber security technology helps ensure that field communications are up-to-date and protected from cyber threats. The IoT solution makes fast, accurate adjustments to boost production and minimise downtime, with minimal manual support from field engineering crews.
Table 1. Artificial lift production asset management functions. Lift design and selection
Data integration and surveillance
Well modelling and optimisation
Automation and control
Operational management
Selection of lift method
Asset data integration
Evergreen well models
Closed-loop remote control
Service delivery and logistics
Sizing of lift system
Performance monitoring
Lift equipment analytics
Edge computing
Surface system management
Artificial intelligence
Equipment quality and traceability
Surface facilities
Smart alarming
54 | Oilfield Technology Summer 2022
Production forecasting
This solution can be easily deployed at the wellsite and integrates into any standard field equipment. It also integrates with any existing enterprise system hosted on the cloud or on-prem, such as field surveillance packages, avoiding the need for expensive system upgrades.
multiphase flow and PVT correlations that help accurately estimate flow rate in gassy and viscous applications. The flowmeter does not require periodic maintenance and additional sensing technology to measure flow – it uses the parameters calculated from the existing downhole gauge.
Virtual flow metering
Fibre optic measurements
Precision, accuracy, repeatability, and sensitivity of physical flow and gauge measurement are critical and require periodic calibration. It is not uncommon to see 10 – 15% inaccuracy in these measurements. Therefore, a virtual sensor can provide credible ESP pump-related parameters such as pump flow, intake pressure, discharge pressure, and reservoir properties such as static pressure, water cut and gas oil ratio (GOR). A good understanding of inflow performance helps an ESP operator to define the most efficient and optimal operating envelope. Traditional flow measurements are costly and time-consuming. The mechanical sensors can fail due to normal wear and tear, harsh well conditions, or manufacturing defects. A virtual sensor can therefore cost-effectively provide accurate measurements. Also, ESP operators do not have to pull the whole ESP equipment string to replace the failed sensor. This can avoid expensive workovers and non-productive downtime, which helps in reducing operating costs. The best way to diagnose conditions that impact well production is to measure production rates directly. NeuraflowTM multiphase flowmeter is a virtual flow metering technique that alleviates issues commonly associated with conventional flow monitoring. It takes downhole and variable speed drive measurements and known reservoir and fluid properties to infer a flow rate. The reservoir and fluid properties are modelled using
Data from downhole fibre-optic sensors, such as SureVIEW™ distributed temperature sensing (DTS), distributed strain sensing (DSS), and distributed acoustics sensing (DAS), when combined with other surface and downhole information, can provide valuable insights about well integrity and production performance. The ProductionLink optical solution simplifies the management and integration of data by using industry standard PRODML (production mark-up language) protocol. It provides an interactive web interface to visualise time and depth series fibre data for each asset, enabling quick identification of trends, patterns, and anomalies that can diagnose downhole conditions, enhance production, and improve overall recovery. The dashboard provides integrated visualisation of the different data types, including data from well logs, well schematics, and well trajectory.
Conclusion
Identifying artificial lift systems’ abnormal operating conditions and spotting trends in advance provides the opportunity to maximise well production, extend equipment run life, and reduce operating costs. The ProductionLink integrated production optimisation platform puts operators in control with operational intelligence, advanced analytics, edge computing, and automation for all methods of artificial lift.
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