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Birkeland, Steinar (Equinor) | Veire, Gunnar (Equinor) | Holm, Christian (Equinor) | Samuelsen, Hans Jørgen (Equinor) | Torgersen, Jan Arne (Equinor) | Nordang, Håkon Fonseca (Equinor) | Lossius, Vibeke (Equinor) | Mjølnerød, Nils (Lundin Norway AS)
As part of the operator's efforts to combat climate change going forward, the operator intends to reduce annual emissions from its oil and gas operations on the Norwegian Continental Shelf (NCS) by 40% within 2030, and to near zero by 2050. To achieve these emission reduction targets, the operator pursues energy efficiency measures, flaring elimination, electrification, floating offshore wind farms and other low-carbon solutions.
Johan Sverdrup coming on stream plays a key role in the operator's ability to deliver on its international climate commitments. With recoverable resources of 2.7 billion barrels and a field lifetime of more than 50 years, identifying solutions for the Johan Sverdrup field development that minimize emissions from production was key to the concept selection process.
The national regulatory and policy context in Norway also played a role. Norway was one of the first countries in the world to introduce a carbon tax, in 1991, and has been a member of the ‘cap and trade’ European Union Emissions Trading System (EU ETS) since 2008, which in effect puts a relatively steep price on carbon emissions from the petroleum sector. In addition, Norway's international climate commitments, with a target to reduce green-house gas emissions by 30% in 2020 relative to 1990 levels, also set clear expectations (even requirements for phase II of the development) for minimizing emissions from the Johan Sverdrup field. The result is a field with one of the lowest carbon emissions from production worldwide, with less than 1kg CO2 per barrel of oil equivalent produced.
This paper starts by elaborating on the context and the strategic, regulatory and technical drivers for minimizing emissions from production from the Johan Sverdrup field. It then explores technologies and solutions chosen to minimize emissions – including, primarily, electrification by means of an HVDC (High Voltage Direct Current) power-from-shore solution but also energy-efficiency measures to optimize the utilization of the available power. The paper concludes by attempting to summarize lessons-learned of relevance for other oil and gas fields, also outside of the regulatory context of the Norwegian continental shelf.
In the same year that the Norwegian Continental Shelf (NCS) celebrates 50-years since the Ekofisk discovery in 1969, which in earnest established Norway as an oil and gas nation, the start-up of the Johan Sverdrup development will extend profitable oil and gas production with lower carbon emissions from the NCS for another five decades.
The third largest oil field on the NCS, after the Ekofisk and Statfjord fields, and with recoverable reserves estimated at 2.7 billion barrels of oil equivalent, Johan Sverdrup certainly has the resources to be a North Sea giant. However, being a giant is more than having the necessary resources in place, it is also about turning these resources into recoverable reserves that can be produced in a safe, profitable and – increasingly in today's context – carbon efficient way.
This paper provides a high-level summary of the experiences and lessons-learned from the development of the Johan Sverdrup field, and has the objective of serving as an introduction to the technical session papers that follow. As such, the paper aims to highlight what it took to make Johan Sverdrup a true North Sea giant, fit for the 21st century: a safe and successful execution of a mega-project, with next-generation facilities adapted to a more digital way of working, with an ambition to profitably recover more than 70% of the resources, while limiting carbon emissions from production to a minimum. The Johan Sverdrup development has set a new standard for project execution in Equinor, the paper concludes with lessons-learned of relevance for both Equinor's future project portfolio and projects globally.
This paper focuses on the execution of phase 1 of this mega-project - from the concept selection and engineering phase, to the global contracting strategy, through the construction across up to 30 building sites globally and until the end of the completions phase offshore Norway - attempting to explain what went well and why, and highlighting potential lessons of relevance to other offshore mega projects on the NCS and globally. Among other things, the paper looks at the impact of different variables in explaining the improvements made during the execution of the project - market effects, procurement strategies, scope optimization and execution performance. The paper then shows that while market effects played an important role - in part reflecting a project being sanctioned at the beginning of the recent oil and gas downturn - the true driver of the success of the project is found elsewhere. As phase II of the Johan Sverdrup development is already underway, the paper also looks at efforts made to sustain these drivers of success into the second phase of the project. The paper also describes which parts of the improvement journey that may not be necessarily replicable in the next stage of the megaproject.
The Operator and the license partnership have set an extremely high ambition for recovery from the Johan Sverdrup field, even before a barrel of oil has been produced. How is this possible? This paper describes the characteristics of the reservoir, as well as early assessments and investments for improved oil recovery (IOR) to ensure flexibility. In addition, data acquisition, reservoir monitoring, new technologies and digitalisation, as well as new ways of working are addressed. This will be the key enablers for a recovery of more than 70% of the field’s oil resources.
Johan Sverdrup is the third largest oil field on the Norwegian Continental Shelf (NCS) with a recoverable volume range of 2,2 to 3,2 billion b.o.e. The reservoir is characterized by excellent reservoir properties with a strongly undersaturated oil. The primary drainage strategy is water flooding, including re-injection of all produced water, supplemented by water-alternating-gas (WAG) injection at the end of the oil production plateau. The field came on stream in October 2019.
Going back to the early stages of the Johan Sverdrup field development, it was obvious from the start that this would be an independent development solution with a long lifetime. Given the excellent reservoir, this was considered as a unique opportunity to plan for a high resource exploitation, and make sure that future business opportunities in this context could be utilized in a technical and economically attractive way.
A very early screening was conducted to investigate which IOR measures should be further matured. With subsurface evaluations as the base, this maturation also included assessments on technical feasibility and potential implications for development solutions. The objective was to ensure sufficient flexibility in early field design. It also implied that the Johan Sverdrup license had to consider pre-investments prior to any implementation decision.
Data acquisition and reservoir monitoring strategies were also started early on, which e.g. led to a full field Permanent Reservoir Monitoring (PRM) decision, with installation starting summer 2019. This gives a baseline for parts of the field before production start, and when completed in 2020 it will be the world’s largest fiber based PRM system. Fiber optics are also installed in the wells. In addition, a dedicated observation well is part of the development plan. The idea is that PRM and fiber data results, in addition to repeated logging in the observation well, will be key information to evaluate business cases for future IOR or new technology measures.
Digitalisation has also been a key aspect of this, and several subsurface-focused digitalisation initiatives have been implemented during the field development, giving the operator the opportunity to implement new ways of working and enabling new ways of cooperation in the partnership as data and applications are shared within the owner group in a digital setting. The overall objective of digitalisation in this context is to further optimize the analysis and management of the Johan Sverdrup reservoir – and hence value of the Johan Sverdrup field – for the license owners.
Nilsen-Nygaard, Viktor (Equinor ASA) | Hanssen, Ståle (Equinor ASA) | Groenewegen, Matthijs (Allseas Engineering B.V.) | Vlaanderen, Stef (Allseas Engineering B.V.) | Apeland, Kjell Edvard (Equinor ASA) | Berge, Jan Olav (Equinor ASA) | Instanes, Frode (Equinor ASA) | Armstrong, Michael A. P. (Isotek Oil&Gas Ltd)
In order to deliver on the ambitious schedule for the Johan Sverdrup development, the operator and the Johan Sverdrup-partners also needed to make some innovative bets on new technology. This paper explores two areas - innovations in installation and pipeline technology - that played a key role in the development of the mega-project. In particular the decision to qualify and become the world s first user of the single-lift installation technology developed for the vessel Pioneering Spirit ended up changing the very concept for construction, installation and completion of three of the four topsides that make up the Johan Sverdrup field center in the first phase of the development. The technology - developed by the installation contractor and qualified for first use worldwide by the operator - saved an estimated 2.5 million offshore manhours from the offshore completion phase, which significantly reduced safety risks and helped shave months off the development schedule. The first-ever use of the technology to install topsides took place in June 2018 with the singlelift installation of the drilling platform topsides on the Johan Sverdrup field. And in March 2019, the two remaining topsides weighing a total of 44,000 tonnes were lifted in place in the span of only 3 days, including the heaviest offshore lift ever executed with the installation of the 26,500 tonnes processing platform. The paper also intends to explore how the same innovative mindset and focus also played a role in introducing new pipeline technology - in particular, the world s first use of remote-controlled and diverless hyperbaric welding of the ''36 oil export pipeline to the Johan Sverdrup riser platform. The paper also discusses how the project benefited from further industrialization of the hot-tapping technology used for the first time by the operator in 2012 on the Åsgard subsea project, when connecting the Johan Sverdrup gas export pipeline to the'live' Statpipe gas pipeline.
The pre-drilling campaign for the Johan Sverdrup development was a key contributor to the successful execution of the first phase of the mega-project. The initial pre-drilling plan consisted of drilling six (6) oil producers, seven (7) subsea injectors and one (1) pilot target. At the end of the campaign, however, as many as eight (8) oil producers, twelve (12) subsea injectors and six (6) pilot targets had been drilled, more than one year ahead of the original schedule and NOK 7 billion (nearly 800 million USD) below budget. All the wells in the pre-drilling campaign were drilled by the semi-submersible drilling unit Deepsea Atlantic (Odfjell Drilling) and the objectives were met on all wells. After a summary of the results of the campaign, the focus of this paper is to identify some of the key success factors behind the campaign and attempts to draw lessons-learned of relevance to future drilling campaigns. Key areas to be assessed in the paper include: contract strategies including the use of integrated service and rig contracts with common incentives to develop and maintain a "One-Team" mentality; the further development of the'perfect well' approach and Lean methodology to minimize waste and maximize efficiency of the campaign; as well as efforts and arenas to systematically promote collaboration, openness and regular experience transfer among the different parties involved (operator and contractors). Since the pre-drilling campaign was completed, the Johan Sverdrup project has successfully tied back, completed and started production of the eight (8) pre-drilled oil producers and injection in the twelve (12) subsea injectors.
A Cost-Effective Subsea Rock Removal Tool for Deepwater application was developed for removal of subsea rock outcrops at 300-500m water depth in the Norwegian Fensfjorden. Subsea rock outcrops were restricting pull-in of the 36” oil export line from the Johan Sverdrup field to Mongstad through a 48” borehole, and a simple low-cost method for subsea rock removal without the use of explosives was developed for this purpose. The developed method reduces the need for traditional seabed intervention and hereby reduces the number of days involving Marine Installation vessels. This contribute to a positive impact on overall cost, HSE and Carbon Emission. The simplification is combining already existing subsea tools into one new tool for subsea solid rock removal. The application was successfully used in Fensfjorden for three different tasks October/November 2017 and March 2018. The method adds a new tool to seabed intervention, making route selection and pipeline installation in near shore areas with challenging seabed more flexible.
Deep water rock formations have traditionally been avoided during pipeline route selection instead of being modified to allow for safe pipeline installation. This is mainly due to lack of proven tools for deep-water rock removal and/or due to high costs for the operation. For the deep-water challenges on the Johan Sverdrup project the use of conventional drill and blast methods was investigated but found to represent a too high risk. This was because of the proximity to existing live pipelines in the fjord and no reference to any previous rock removal, using drilling nor blasting at this water depth. Scanmudring was approached by Equinor to perform a feasibility study for the rock removal required at the landfall tunnel exit area outside Mongstad to allow for a safe pull-in of Johan Sverdrup oil pipeline. The feasibility study evaluated a wide range of available tools for subsea rock removing, all tools suitable of being mounted on the existing Scanmudring hydraulic subsea excavator. Based on the analysis of the rock formations outside Mongstad showing a high degree of faulting and fractures, it was expected that rock breaking equipment would be the best solution to remove the desired amount of rock. In addition, the study produced by Scanmudring also recommended the use of drilling-and rock splitting equipment as a back-up solution if use of the rock breaker should prove to be insufficient. Both proposed methods were based on use of Scanmudring hydraulic subsea excavator (Scanmachine#3) mounted in a subsea basket, hanging 15m above seabed from the vessel crane, as the work area could not be reached by the machine when resting on the seabed. Hanging from the crane opened for work at any height above seabed, but it also introduced uncertainties with regards to great strain on equipment and required the vessel to be fully involved in the operation at all time. The rock removal tools were designed and built in less than 6 months, from feasibility to operation, and was successfully used on the Johan Sverdrup Project removing rocks on deep water outside Mongstad. In fact, the cost-effective use of the rock removal tool outside Mongstad revealed that the tool could be used for other seabed intervention tasks on the same project, and Scanmudring was requested by Equinor to remove outcrops at two locations further out the pipe line route in Fensfjorden, on the west coast of Norway. This paper will first present the tools developed for cost-effective deep-water rock removal, and then describe the successful use of the rock removal tools for the Johan Sverdrup project.
Equinor To Employ Permanent Reservoir Monitoring at Arctic, North Sea Fields
Matt Zborowski, Technology Writer
Equinor will use permanent reservoir monitoring (PRM) to help improve recovery in two of the operator’s more important offshore projects of the next few years.
The Norwegian state-owned operator has exercised an option in an existing framework agreement with Alcatel Submarine Networks (ASN) to implement the technology at its Johan Castberg field in the Barents Sea. That framework agreement was reached in January for PRM deployment at the Johan Sverdrup field in the North Sea.
The technology involves the permanent installation of seismic sensors on the seabed, enabling the operator to continually monitor reservoir changes—with better images—throughout the lifespan of a field. Equinor said the information generated from PRM will aid its overall efforts in visualization, modeling, and, eventually, predictive analyses.
Directional Drilling Services Market Grows in 2017, Near-Term Upward Trend Expected
Stephen Whitfield, Senior Staff Writer
A new report from Spears & Associates paints a positive picture for the global directional drilling services market as it recovers from the oil-price down-turn. After falling from $16.5 billion in 2014 to $7.1 billion in 2016, market growth is projected to accelerate in the near term.
The directional drilling services market grew 16% in 2017 as increased horizontal drilling activity in the US and longer per-well lateral length offset a faster penetration rate. Richard Spears, vice president of Spears & Associates, said that lateral length has created an enormous demand for directional drilling services even though rig counts are still not high.
“It doesn’t even matter that much what the drilling rig count is,” Spears said. “The question is how many feet are being drilled in the horizontal section? That’s the only metric that matters. If I’m drilling 10,000-ft laterals and 12,000-ft laterals and 20,000-ft laterals, that just means there’s a greater intensity of use for directional drilling services every day, every quarter.”
Bids, Dollars Rise in Third Regionwide US Gulf of Mexico Lease Sale
Matt Zborowski, Technology Writer
The third regionwide US Gulf of Mexico lease sale drew more bids and more money than the first two, providing, for now, another reason for optimism in an offshore industry hungry for a resurgence.
Lease Sale 251 drew 171 bids on 141 blocks with high bids totaling $178.1 million, up 43% from the last regionwide auction in March, the US Bureau of Ocean Energy Management (BOEM) announced from New Orleans on 15 August. Twenty-nine companies submitted bids, including the usual group of participants consisting of majors and big independents from past lease sales.
Offshore operators showed “their continued confidence in the region,” said William Turner, senior research analyst at Wood Mackenzie, in comments following the event. The improved results came in spite of less acreage being made available compared with the March auction—the largest ever—and the government’s unwillingness to budge on recommended cuts to offshore royalties.
Diamondback Energy Spending $10.5 Billion in Permian Acreage Expansion
Matt Zborowski, Technology Writer
Diamondback Energy Inc. is amassing billions of dollars’ worth of Permian basin acreage in a pair of deals that rivals recent acquisitions by BP and Concho Resources.
In the biggest, reported 14 August, Diamondback agreed to acquire Energen Corp. in an all-stock deal valued at $9.2 billion, including Energen’s net debt of $830 million. A week earlier, Diamondback said it agreed to buy Ajax Resources for $1.25 billion.
The deals will give Diamondback 390,000 net acres across the Midland and Delaware Basins, up 85% from 211,000 net acres as of 30 June. This includes 266,000 net “tier one” acres and 7,000 estimated total net horizontal locations, the company said in a statement.
Controlled buckles in subsea pipelines exposed to expansion forces can be triggered by various methods such as snake-lay, installing sleepers/berms, or the residual curvature method (Statoil patent, 2002). The latter (RCM) is relatively new but is gaining popularity and has now been successfully applied to four pipeline projects. During installation, short sections of residual curvature in the vertical direction are introduced to the pipeline, and these introduce a rotationally destabilising effect. Different as-installed configurations may result: the residual curvature section may rotate over into the horizontal plane on the seabed; or it may remain vertical. If it remains vertical, self-weight can cause the pipe to slump down onto the seabed and become straightened.
When applying the RCM, it is preferable for the pipeline to rotate approximately 90° during installation, for the purposes of reducing the critical buckling force and avoiding the introduction of artificial free-spans at the residual curvature sections. Therefore it is important to analyse the rotation behaviour at the design stage. Rotational fixedness at the lay-vessel and resistance from soil friction act to restrain the pipe, but experience from, for example Statoil’s Skuld Pipeline Project, indicates that the residual curvature sections tend to rotate. Recent analysis work on rotation during installation of the Johan Sverdrup in-field pipelines is presented. The shallower depth reduced the tendency to rotation compared to reference projects, and the analysis results were used to guide installation settings to assure a robust rotation response during lay.
Subsea pipelines may twist during installation from a lay vessel due to mechanisms that generate torque. This leads to rotation of the pipe cross section. The torque can be generated by, for example route curves, or the weight of inline structures. The rotation phenomenon may be characterised as an instability, as in the case of top-heavy structures which only generate a torque when their centre of gravity becomes laterally displaced from the axis of the pipe. Another type of rotational instability is that caused by plastic hogging bending in the pipeline. This can originate in, for example, a mild constant plastic straining on an S-lay barge’s stinger, or a purposeful manipulation of the straightener settings during reel-lay. Since the suspended pipe between the lay vessel and the touchdown point (TDP) is dominated by sagging, there can be a net decrease in potential energy if the plastic bending becomes rotated to better match the imposed sagging bending (see Bynum & Havik, 1981).
Every dataset exhibits distinct and non-stationary challenge.