Recovering More Than 70% From the Johan Sverdrup Field
Before the giant Johan Sverdrup field had produced even one barrel of oil, operator Equinor and its license partners set a recovery ambition of greater than 70% for the field.
Before the giant Johan Sverdrup field had produced even one barrel of oil, operator Equinor and its license partners set a recovery ambition of greater than 70% for the field. The complete paper discusses key elements driving this ambition. These include the field size and reservoir characteristics, early assessments and investments for improved oil recovery (IOR), data acquisition, reservoir monitoring, and digitalization.
With a recoverable volume range of 2.2–3.2 billion BOE, Johan Sverdrup is a giant oil field approximately 150 km west of Stavanger, the third-largest oil field on the Norwegian Continental Shelf (NCS). The reservoir features hydrostatic pressure and undersaturated oil with a low gas/oil ratio (GOR). The first phase of the field came on stream in October 2019. A predrilling campaign included eight oil producers and 12 injectors.
The field is being developed in two phases. Phase 1 includes four bridge-linked platforms:
- Living quarters with utility-system functions
- Process platform
- Drilling platform
- Riser platform (RP) with tie-in of onshore power
Three injection templates are tied back to the RP. All platforms have jacket substructures. Main power to the field is from shore. The full field development includes 64 platform and subsea wells.
Phase 2 of the development was approved in 2019 and is expected to start production in Q4 2022. It includes development of another processing platform, modifications of the RP and the field center, five subsea production and injection templates, and power-from-shore supply. The central area with highest hydrocarbon thickness and the highest relief to the free water level was chosen for the field-center location.
Fluid Characterization and Data Acquisition
Reservoir pressure in Johan Sverdrup is at hydrostatic level, and the reservoir oil is strongly undersaturated, with low GOR (approximately 40 Sm3/Sm3). Density and viscosity values are moderate (approximately 800 kg/Rm3 and 2 cp, respectively). No initial gas cap exists, and the minimum miscibility pressure is much higher than the reservoir pressure.
An extensive and consistent data-acquisition program was carried out during the exploration and appraisal period. Forty-two exploration and appraisal wells, including sidetracks, have been drilled on or near the structure. Extensive coring of the reservoir intervals was performed, with subsequent sedimentological interpretation and extensive conventional and special core analyses. Full wireline logging programs, including wireline formation tester with fluid sampling, were run close to all wells.
Drillstem tests (DSTs) in selected wells supplied valuable information on reservoir communication and dynamic behavior. The DSTs in the intra-Draupne sandstones indicated excellent permeability and good communication over long distances and across faults. The DST data have influenced modeling of permeability, faults, relative permeability, and sand distribution through an iterative model-building process.
Several seismic surveys, including broadband streamer seismic data and oceanbottom seismic, were acquired during the exploration and field-development phases.
Altogether, the acquired static and dynamic database formed a solid foundation for building reservoir models, establishing field-drainage strategy, and assessing the potential of future IOR measures. This further enabled adaptation of field-development plans to future IOR requirements. The relative permeability laboratory data suggest that the residual oil saturation to water flooding can be very low, between 6 and 13%. Analytical evaluations of the relative permeability indicate the potential recovery to be greater than 70% in the intra-Draupne sandstones and slightly lower in the Statfjord Group.
The dimension of the field and the need to secure flexibility in the development led to an early decision for a phased development with a field center. Water injection combined with gas lift was selected as the drainage strategy. The primary drainage strategy is waterflooding, including reinjection of all produced water, supplemented by water-alternating-gas (WAG) injection at the end of the oil-production plateau. Produced water reinjection at this scale has not been attempted before on the NCS and was therefore identified as a main risk. Several mitigating actions were implemented for safe injection.
The water-injection-drainage strategy, discussed in detail in the complete paper, has focused on achieving optimal drainage of both the intra-Draupne sandstones and the underlying reservoirs. Dedicated production and injection wells are planned to account for possible poor vertical communication between the very permeable intra-Draupne sandstones and the underlying reservoir of lower permeability in the Statfjord Group.
While IOR traditionally is considered toward the end of a field life, early IOR considerations and studies to include the necessary flexibility in field design can be both economically and strategically justified. The Johan Sverdrup reservoir and fluid properties place it among the least-complex fields in the North Sea, giving a recovery factor range in the range of 60 to 70%. While the extremely high permeability, high net-to-gross ratio, and good reservoir communication as estimated from DSTs pull the recovery factor into the higher end of the range, negative factors include relative flatness of the field, the large area, and the relatively higher viscosity compared with that of other large North Sea fields.
A WAG technique in which water injection and gas injection are carried out alternately for periods of time to provide better sweep efficiency and reduce gas channeling from injector to producer was selected as the IOR methodology. Infill drilling may be a major contributor to increased recovery. Available spare slots on the subsea templates and the drilling platform and possibilities for sidetracks allow targeting of infill locations identified by permanent reservoir monitoring (PRM).
4D seismic monitoring solutions were discussed early in the field-development phase. Installation of a full-field PRM system began in summer 2019. This provides 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. A dedicated observation well is also 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 to evaluating business cases for future IOR or new technology measures. The selection and installation process and operation of the PRM system and the observation well are detailed in the complete paper. The full-field PRM system is shown in Fig. 1.
Downhole fiber has been installed (to top reservoir) in predrilled producers, while fiber optics are planned in selected producers and injectors, also in the reservoir sections, to monitor well performance with respect to safety and production optimization.
Digitalization is a key aspect of the field-development plan, and several subsurface-focused digitalization initiatives have been implemented, providing the opportunity to implement new ways of working and cooperating as data and applications are shared within the owner group in a digital setting. The overall objective of digitalization in this context is to further optimize the analysis and management of the Johan Sverdrup reservoir, and thus the value of the Johan Sverdrup field, for the license owners.
A technology-development strategy for the field was first established before Phase 1, with the aim of identifying life-of-field value-adding technologies. The strategy was revised before Phase 2 with a strong focus on identifying enablers for a field recovery of greater 70% and increased production efficiency. The field’s digital roadmap, established in 2017, has several subsurface-focused initiatives and complements the technology strategy. Digital initiatives implemented during field development had two main focuses.
- Ensure the large amount of data that will be acquired on the field can be efficiently used to further optimize analysis and management of the reservoir
- Explore possibilities for new work flows and cooperative systems
Subsurface digitalization activities in the development phase include automating reservoir modeling and PRM work flows, making subsurface data available on the operator’s cloud-based platform solution, and establishing cross-disciplinary visualization tools to aid in reservoir description, modeling, and well planning. In the future, linking subsurface models to online process and drilling simulators and to the digital twin of installations has the potential to improve real-time decision-making. Additionally, automatic control and optimization functionalities have been implemented to prepare the field for automated production optimization, with the aim of increasing production and energy efficiency, especially after plateau.
Following the decision to install fiber-optic cables in wells with dry wellheads, a larger digitalization project was initiated to handle transfer, processing, storage, and analysis of data flow constantly generated from the well fiber optics. The plan is to use distributed fiber data to improve both health, safety, and environmental surveillance and production and reservoir monitoring in real time.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 30525, “Toward a Recovery Ambition of More Than 70% for the Johan Sverdrup Field,” by Eli Eikje, SPE, Tone Nedrelid, and Elisabeth Bratli, Equinor, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission.