Troll Field Research Articles

Potential secondary seals within overburden: Observation from the CO2 storage sites Aurora and Smeaheia, northern North Sea

This study evaluates potential secondary seals within the overburden in two CO2 storage sites, Aurora and Smeaheia within the Horda Platform area, of the northern North Sea. Secondary sealing intervals provide for safe and reliable CO2 storage as they prevent injected fluids from migrating into the atmosphere in the case of primary seal failure. This study analyzes the possible fate of the CO2 plume in the case of primary seal failure for the Aurora and Smeaheia CO2 storage sites by evaluating the secondary caprock and sealing potential of polygonal fault systems within the overburden intervals using structural reliability methods. Our findings suggest that a ductile secondary caprock is present in the overburden intervals of the storage sites, which could act as a secondary seal in the case of primary seal failure. The trapped hydrocarbon leaked from the Troll field within this ductile unit indicating a good secondary sealing potential. The study also reveals the presence of polygonal fault systems in the entire study area, but their frequency and orientation vary between layers. However, polygonal fault systems are not structurally stable, posing a risk of fault-parallel flow within the overburden interval. Nonetheless, the ductile clay-rich secondary caprock provides a seal for the polygonal fault systems within the interval. Due to either erosion or non-deposition, the ductile rock interval is not present in the east of the study area. As such, the critical risk for the Alpha structure in the Smeaheia injection site is the Vette fault and the efficiency of the primary Draupne caprock. Moreover, the crucial factor in the western Aurora site is the connectivity between the depleted Troll reservoirs and the CO2-injected pressurized reservoirs underneath. Based on our qualitative assessment, it is concluded that the overburden interval in the Horda Platform has adequate secondary sealing potential to hold and accumulate CO2 in the case of primary seal failure. Still, further numerical simulations are recommended to quantify our findings for both the Aurora and Smeaheia sites.

The Impact of Autonomous Inflow Control Valve on Improved Oil Recovery in a Thin-Oil-Rim Reservoir

Summary Oil production from thin-oil-rim fields can be challenging as such fields are prone to gas coning. Excessive gas production from these fields results in poor production and recovery. Hence, these resources require advanced recovery methods to improve the oil recovery. One of the recovery methods that is widely used today is advanced inflow control technology such as autonomous inflow control valve (AICV). AICV restricts the inflow of gas in the zones where breakthrough occurs and may consequently improve the recovery from thin-oil-rim fields. This paper presents a performance analysis of AICVs, passive inflow control devices (ICDs), and sand screens based on the results from experiments and simulations. Single- and multiphase-flow experiments are performed with light oil, gas, and water at typical Troll field reservoir conditions (RCs). The obtained data from the experiments are the differential pressure across the device vs. the volume flow rate for the different phases. The results from the experiments confirm the significantly better ability of the AICV to restrict the production of gas, especially at higher gas volume fractions (GVFs). Near-well oil production from a thin-oil-rim field considering sand screens, AICV, and ICD completion is modeled. In this study, the simulation model is developed using the CMG simulator/STARS module. Completion of the well with AICVs reduces the cumulative gas production by 22.5% and 26.7% compared with ICDs and sand screens, respectively. The results also show that AICVs increase the cumulative oil production by 48.7% compared with using ICDs and sand screens. The simulation results confirm that the well completed with AICVs produces at a beneficial gas/oil ratio (GOR) for a longer time compared with the cases with ICDs and sand screens. The novelty of this work is the multiphase experiments of a new AICV and the implementation of the data in the simulator. A workflow for the simulation of AICV/ICD is proposed. The simulated results, which are based on the proposed workflow, agree with the experimental AICV performance results. As it is demonstrated in this work, deploying AICV in the most challenging light oil reservoirs with high GOR can be beneficial with respect to increased production and recovery.

Time‐lapse applications of the Marchenko method on the Troll field

AbstractThe data‐driven Marchenko method is able to redatum wavefields to arbitrary locations in the subsurface, and can, therefore, be used to isolate zones of specific interest. This creates a new reflection response of the target zone without interference from over‐ or underburden reflectors. Consequently, the method is well suited to obtain a clear response of a subsurface reservoir, which can be advantageous in time‐lapse studies. The isolated responses of a baseline and monitor survey can be more effectively compared; hence, the retrieval of time‐lapse characteristics is improved. This research aims to apply Marchenko‐based isolation to a time‐lapse marine data set of the Troll field in Norway in order to acquire an unobstructed image of the primary reflections and retrieve small time‐lapse traveltime difference in the reservoir. It is found that the method not only isolates the primary reflections but can also estimate internal multiples outside the recording time. Both the primaries and the multiples can then be utilized to find time‐lapse traveltime differences. More accurate ways of time‐lapse monitoring will allow for a better understanding of dynamic processes in the subsurface, such as observing saturation and pressure changes in a reservoir or monitoring underground storage of hydrogen and CO2.

Life cycle cost analysis of a floating wind farm in the Norwegian Sea

The offshore wind energy industry has witnessed rapid growth in the past decade. Still, there is a lack of commercial floating wind projects due to the relatively high development costs and other factors. To facilitate the holistic evaluation of floating wind farms in Norway, this article investigates the levelized cost of energy of a floating offshore wind farm and its economic feasibility. The Troll field west of Bergen, Norway, is assumed to be the target offshore site, and a farm size of 50 wind turbines with a lifespan of 25 years are considered. Each floating wind turbine has a 15-megawatt turbine mounted on a semi-submersible floater. Based on detailed analysis, the levelized cost of energy of the wind farm is estimated to be approximately 100.7 $/MWh. The capital expenditure is the most prominent cost and constitutes 63.1% of the total cost, and the operational expenditure constitutes the remaining 36.9%. Further, sensitivity analyses show the influence of the lifespan, capacity factor, and project discount rate on the levelized cost of energy. The present study contributes to techno-economic evaluation of floating wind projects at an early phase.

Case Study: Oil Production Optimized With Autonomous Inflow Control Devices Offshore Malaysia

_ Advanced well completions have proven to be an effective method of moderating gas breakthrough while producing a thin oil rim when placed in a heterogenous, carbonate reservoir. In addition, several studies have proven that the application of autonomous inflow control devices (AICDs) acts as a type of insurance policy against geological and dynamic reservoir uncertainties to reduce the risk and variation in the expected oil production profiles. During 2019 and 2020, Sarawak Shell Berhad conducted development campaigns in the central Luconia province in a thin oil rim carbonate reservoir offshore Sarawak, Malaysia. The horizontal, approximately 6,000-ft development wells were expected to intersect with different geological layers with varying rock properties, resulting in an uneven reservoir influx toward the wellbore. Oil production from these wells was expected to suffer severely from early gas and water breakthrough. To produce the oil rim without the risk of early gas production, global production optimization specialist, Tendeka, incorporated FloSure AICDs in the lower completion design at the reservoir interface along the horizontal section of the wells. As an active flow control device, the technology delivers a variable flow restriction in response to the properties of the fluid entering the wellbore and the rate of flow passing through it to help manage gas coning/cusping risks. The fluid is then lifted to surface with natural in-situ gas lift built into the upper completion. A three-phase development was planned for the field, and to date, two phases have been completed. New-Generation ICD The first AICD completion was installed in Norway in 2008 and widely implemented in the Troll field in 2013 with very encouraging results (SPE 159634). However, its use is relatively new to both the Asia Pacific region and this type of application. Similar to a standard ICD which balances the influx of reservoir fluids, the FloSure AICD will delay the production of unwanted effluents prior to their breakthrough (proactive solution). However, once a breakthrough occurs, the device restricts the production of unwanted effluents with lower viscosity, such as gas (in light oil applications) and both gas and water in viscous oil production (reactive solution) (OTC 30403, OTC 30363, SPE 193718). The device delivers a variable flow restriction in response to the properties of the fluid and the rate of flow passing through it. Flow enters the device through the nozzle in the top plate of the body. This impacts the disk and spreads radially through the gap between the disk and the top plate, then turns around the top plate and is discharged through several outlet ports in the body (Fig. 1). The overall geometry of the device is critical to its ability to balance these forces effectively and create the desired fluid-dependent pressure drop. Field A employed 7.5-mm AICD valves to match the performance of the devices to the potential well flow rate. The oil, water, and gas viscosities are 0.40 cP, 0.27 cP, and 0.018 cP, respectively, at downhole flow conditions.

A regionally consistent 3D seismic-stratigraphic framework and age model for the Quaternary sediments of the northern North Sea

The thick succession of Quaternary sediments that is preserved in the northern North Sea provides a valuable record of the climate and environmental changes of the last ∼2.6 million years. However, the general lack of chronological control on these sediments, combined with gaps in high-resolution seismic data coverage, has hindered our understanding of the detailed sediment infill history of this margin. Here we use a large (35,000 km2) high-resolution 3D seismic cube, supplemented by other 2D and 3D seismic datasets, to map more than 20 horizons within the Quaternary Naust Formation. We extend these horizons across large parts of the northern North Sea to establish a robust seismic framework that is used to assess the correspondence between existing chronostratigraphic ages. Whereas there is good agreement between most existing ages, the correlation of horizons between the Troll Field and the North Sea trough-mouth fan suggests that the sediments preserved at the base of the Norwegian Channel may have been deposited significantly later than assumed previously. Geomorphological forms preserved close to the base of the Norwegian Channel provide evidence for sediment disturbance by ice-stream activity, and document a two-stage glacial build-up during a mid-Pleistocene glaciation. We suggest a new age model for the Quaternary sediments of the northern North Sea, in which the deposition of sediments within the Norwegian Channel occurred as recently as 0.35 Ma in response to prior sediment loading and subsidence within the North Sea trough-mouth fan. In addition to providing new insights into the extent and timing of glacial events, the development of a regionally consistent 3D seismic-stratigraphic framework has implications for the age of the Peon gas discovery and for reconstructing spatial and temporal patterns of Quaternary sediment subsidence and fluid overpressure in the North Sea Basin.

Overburden analysis and seal integrity study for CO2 sequestration in the North Sea (OASIS)

The Norwegian government recently launched a full-scale CCS project (Longship) in the North Sea that will store CO2 captured from Norway and other European countries. One of the proposed CO2 storage sites is “Smeaheia,” located east of the Troll oil and gas field, northern North Sea. Another neighboring prospective storage site, “Aurora” is located south of the Troll field. With a history of oil and gas exploration and production, Norway possesses all the necessary skills and technology to establish and run sub-surface CO2 storage. The geologic evaluation of an area for CO2 storage warrants detailed characterization of the reservoir, seal and overburden rocks. In the case of a hydrocarbon trap, the oil/gas accumulation manifests the caprock and the overburden integrity. However, in geological CO2 storage, a careful investigation of the reservoir, seal, and overburden rocks can avoid leakage risk. The Smeaheia area is bounded by a fault array separating the Troll field in the west and the Basement Complex in the east. The upper Jurassic Sognefjord Formation sandstone is the target CO2 storage reservoir in the Smeaheia area capped by Heather and Draupne Formations shales. In the Aurora prospect, the Johansen and Cook Formation sandstones of Early Jurassic age around the Troll field are potential storage units. The reservoir is enveloped by Amundsen shale, whereas in the southeast, where the Amundsen shale pinches out, the Drake Formation shale directly overlies the Johansen and Cook Formations. The OASIS project deals with various aspects of the seal and overburden rocks above a potential CO2 reservoir. This study aims to evaluate the viability of the seal and overburden rocks using seismic, well-log, and geological data to make sure the injected CO2 remains safely in the underground forever. The work investigated the seals overlying the potential CO2 reservoirs in the area using various techniques. This information will be used at the later stage of the OASIS project to generate and calibrate a field-scale 3D geomechanical model. To assess the integrity of seal rocks, the brittleness and ductility of shales are essential. If a rock is brittle, there is a risk of developing fractures once the pressure increases while injecting CO2. Conversely, a ductile rock preserves its integrity under high pressure. In the Aurora area, the Amundsen and Drake Formation shales’ brittleness relatively increases with depth and temperature; however, our analysis showed a low possibility of fracturing. The Johansen Formation reservoir sandstone quality is improving towards the south at shallower depths within the Aurora area. According to the rock physics analysis, some calcium-rich, thin baffles are found. In the Johansen Formation reservoir sandstone, at deeper levels, the material binding the sand grains is quartz cement, which decreases where the clay/shale percentage is relatively high. The presence of cement might reduce the void spaces between the sand grains, resulting in a reduction of space for CO2 storage. Using a 3D seismic GN1101 in the Smeaheia area, we decomposed the full frequency spectrum to 20 Hz, 40Hz, and 60 Hz frequency cubes. Draping horizons from the Lower Jurassic Drake Formation up to the seafloor on the RGB blend of the three frequencies enabled identifying various sedimentary features within the window below the respective surface. We also generated a dip-steered “Similarity” cube to identify faults intersecting a formation surface and detect associated fractured areas. Based on the seismic data, formations below Quaternary dip towards the west to south-west with several faults associated with the north-south running Vette fault system close to the western edge of the area. The attributes indicate a sedimentary environment ranging from coastal, shallow marine to open marine within the analyzed interval. Weak fault traces are identifiable on the base Quaternary surface; furthermore, we identified several pockmarks on the Draupne Formation sealing layer and the seafloor. The discontinuities/ faults do not extend from the reservoir to the seafloor. However, one linear impression was observed on the seafloor on the low-frequency spectrum, indicating possible palaeo-leakage of hydrocarbon gas from the underlying strata. The risk of CO2 leakage through the pockmarks and the said fault needs further investigation, though these features are not present above the potential storage structures. The Amplitude Variation with Angle (AVA) technique yields valuable information about the reservoir fluids. The AVA models confirmed that the changes in CO2 saturation and conversion to gaseous state within the reservoir are possible to monitor remotely using a time-lapse seismic or 4D survey. We also extracted mechanical properties from the Smeaheia 3D seismic using pre-stack Inversion. These property cubes will be used for making a geomechanical model that will be calibrated using the information obtained by the methods mentioned above.

Reservoir fluid effect on caprock properties in the Horda Platform area, northern North Sea

Upper Jurassic organic-rich shales' caprock properties in the Horda Platform area are crucial due to their importance as primary seals for the Middle Jurassic reservoir sandstones. The reservoir sandstones are Sognefjord, Fensfjord, and Krossfjord formations. These reservoir sandstones are overlain by the Upper Jurassic Draupne and Heather Formation Shales. Caprock failure due to injection-related pore pressure change is one of the critical risks for CO2 storage. The thick gas column in Troll East Field, located in the Horda Platform area, can consider an analog for a CO2 post-injection scenario in the area. Evaluating the caprock properties above the thick gas column in the Troll Field helps to understand the area's caprock integrity qualitatively. This study assesses Draupne and Heather Formation Shales' caprock properties using petrophysical and rock physical analyses. Four exploration wells from the Troll East area consider in this study where wells 31/3-1 and 31/6-1 have gas columns of approximately 224 and 222 m, respectively, and two other wells (31/3-3 and 31/6-3) are water wet. The exhumation correction suggests that Draupne and Heather Formations of four studied wells' maximum burial depth experienced only mechanical compaction. Two rock physics templates, such as Vp versus density and Young’s modulus versus Poisson’s ratio, are used to evaluate the caprock behavior due to HC accumulation-related overpressure. The caprock shales in wells with gas columns show a significantly soft nature compared to the shale in the dry well 31/3-3. However, a dry well (31/6-3) also shows remarkably low stiffness. The pressure changes due to the HC accumulation might change the pressure above the reservoir. The caprocks may behave more ductile due to the generation of non-connected micro-fractures. However, fracture connectivity might initiate the caprock's mechanical failure, which poses a significant risk in CO2 post-injection scenario. Moreover, a significantly thick caprock in well 31/6-3 may have influenced the caprock properties differently compared to the other dry well. The caprock mechanical behavior is complex and influenced by several factors.

E&P Notes (March 2021)

E&P Notes (March 2021)

Containment Risk Assessment of the Northern Lights Aurora CO2 Storage Site

Assessment of containment (storage site integrity) is a key activity in the evaluation, and a requirement for approval, of potential CO2 storage sites. Here we present the workflow used for, and key results of, the containment risk assessment (CRA) in the Northern Lights project, which is the transport and storage part of the Norwegian “Longship” full-scale CCS project. In the Northern Lights project, CO2 storage is planned to take place at the Aurora site (Exploitation license EL001), southwest of the Troll Field. Injection is planned into the sandstone-rich Johansen Formation (Lower Jurassic Dunlin Group). The argillaceous upper member of the Dunlin Group, the Drake Formation, provides the main seal for the storage reservoir. Several further barrier and baffle units and intervening sandstones are present between the Drake Fm. and the sand-rich units of the Viking Group, which contain the giant Troll field with a high level of depletion to date. The injection site is located downdip of – and stratigraphically deeper than – the Troll West gas province (TWGP). Injected CO2 is expected to move slowly over time buoyancy-driven up-dip (northwards), with a small proportion reaching eventually the structural trap underneath the TWGP. A key method utilized in the Aurora CRA is the bowtie method. Bowties were prepared for each identified “leakage” pathway (according to the definition in the EU CO2 Storage Directive, thus not implying any emission to the water column) instead of per “leakage” mechanism, as has been the case in previous CO2 storage CRAs. The bowties were designed to allow for updates, which took place as new data or interpretations became available. A major update occurred after drilling of a confirmation well at the planned injection site. Key results of the CRA are that the probability of any emissions into the water column due to “leakage” of CO2 out of the storage complex is very low to negligible. Important arguments for this conclusion are (i) the hydraulic separation of the Johansen Formation from the shallower, depleted Viking Group, as attested by pressure data in the confirmation well, and (ii) the proven effectiveness of the seal to the Viking Group sandstones, which have accumulated and stored hydrocarbons over geological time. Further, any CO2 reaching and blending into the hydrocarbon accumulations nearby (such as the Troll Field) is regarded to also have very low probability. Storage Complex Monitoring (SCM) is an integral element of the CRA to enable mitigating actions in case of indications for unpredicted behaviour or “leakage” of the injected CO2.

CO2 Footprint of the Norwegian Longship Project

An analysis of the CO storage efficiency of the Longship project has been performed using a spreadsheet based LCA tool. Results are presented in terms of the CO2 footprint for each value chain measured in units of “tonnes of CO2 equivalent emissions per tonne of CO2 stored underground”. In other words, the results from the tool show the impact of the implementation and operation of the chain on the CO2 storage efficiency. The work was commissioned by Gassnova, the Norwegian State Enterprise for Carbon Capture and Storage. The work was performed by DNV GL and Carbon Limits The method used is consistent with the principles of ISO 14040 “Life Cycle Analysis – principles and framework” and ISO 14044 “Life Cycle Analysis – requirements and guidelines” and has been designed to calculate CO2 equivalent emissions to atmosphere in a 100-year perspective. The functional unit of the system studied is 1 tonne of CO2 stored, where storage refers to permanent geological storage .as defined in ISO 27914 “Carbon dioxide capture, transportation and geological storage – Geological storage”. The tool is capable of accounting for direct and indirect greenhouse gas emissions of each building block of the Carbon Capture and Storage (CCS) chain for the life cycle of the project. As such, for each building block, all project phases are included (construction, operation, decommissioning for capture and transport – construction, injection, post injection, decommissioning and post closure for storage) and for each phase CO2 emissions from the use of fuel, energy, chemicals, materials and transport are considered. In the Longship project, CO2 is captured from two capture sites, the cement factory of Norcem in Brevik and the waste to energy facility at Klemetsrud in Oslo, transported by ship to a receiving terminal at Naturgassparken near Bergen and further transported in a subsea pipeline to the Aurora CO2 storage license area near the Troll field in the North Sea for final geological storage. Three main value chains have been investigated corresponding to each of the two capture sites individually and one combining the two capture sites all with the same sort of transport and storage. Calculation results are then presented as total CO2 footprint measured in tonnes of CO2 equivalent per tonne CO2 stored for the value chain of each capture site separately and for both capture sites combined. In other words, the results from the tool show the impact of the implementation and operation of the chain on the CO2 storage efficiency. In addition, all three alternatives above are estimated when utilizing the full capacity of the storage infrastructure, 1.5Mt/y by introducing CO2 from other sources. The capture from these other sources are not included in the footprint calculations presented. Generally, the Longship project shows very low CO2 footprint compared to projects studied elsewhere. The 3 main reasons for the low CO2 footprint are 1) waste heat or internal steam is utilized for the CO2 capture processes,,2) the Norwegian electricity mix have a very low CO2 footprint and 3) the project has had high focus on using low footprint energy and fuel alternatives wherever possible. Since both capture sites have an element of biologically based raw materials the impact of BioCCS is also discussed as Longship can lead to net negative emissions.

How to Evaluate and Quantify Safe CO2 Storage? Workflow Demonstration on the Smeaheia Area, Offshore Norway

A question that is often raised during discussing around underground CO2 storage in saline quifers, is whether the stored CO2 will stay in place, and how to evaluate and quantify safe storage and ensure acceptable low seepage. In this study a workflow has been tested on a potential subsurface CO2 storage site at the Smeaheia area, offshore Norway. The effect of the pressure depletion from the giant gas Troll Field, starting production in 1995 has been simulated. As a conformance test, the simulated pressure has been compared with measured pressures from a newly drilled exploration well in the study area, with good match. Simulated pressures have used as input to simulate CO2 injection and saturation varying the reservoir heterogeneities. Different conformance tests have been discussed using bottom hole pressure to evaluate potential CO2 injection, or collection new seismic.

Simultaneous joint migration inversion for high‐resolution imaging/inversion of time‐lapse seismic datasets

ABSTRACTThe current time‐lapse practice is to exactly repeat well‐sampled acquisition geometries to mitigate acquisition effects on the time‐lapse differences. In order to relax the rigid requirements on acquisition effects, we propose simultaneous joint migration inversion as an effective time‐lapse tool for reservoir monitoring, which combines a joint time‐lapse data processing strategy with the joint migration inversion method. Joint migration inversion is a full‐wavefield inversion method that explains the measured reflection data using a parameterization in terms of reflectivity and propagation velocity. Both the inversion process inside the imaging/inversion scheme and the extra illumination provided by including multiples in joint migration inversion makes the obtained velocity and reflectivity operator largely independent of the utilized acquisition geometry and, thereby, relaxes the strong requirement of non‐repeatability during the monitoring. Because simultaneous joint migration inversion inverts for all datasets simultaneously and utilizes various constraints on the estimated reflectivities and velocity, the obtained time‐lapse differences have much higher accuracy compared to inverting each dataset separately. It allows the baseline and monitor parameters to communicate with each other dynamically during inversion via a user‐defined spatial weighting operator. In order to get more localized time‐lapse velocity differences, we further extend the regular simultaneous joint migration inversion to a robust high‐resolution simultaneous joint migration inversion process using the time‐lapse reflectivity difference as an extra constraint for the velocity estimation during inversion. This constraint makes a link between the reflectivity‐ and the velocity difference by exploiting the relationship between them. We demonstrate the feasibility of the proposed method with a highly realistic synthetic model based on the Grane field offshore Norway and a time‐lapse field dataset from the Troll Field.

Influence of glaciations on North Sea petroleum systems

Abstract Even in tectonically inactive areas/times, the vertical motions of the Earth's interior may be significant due to glaciation. The most recent ice age massively changed the surface of northern Europe, leading to isostatic re-equilibration. We quantify the vertical motions resulting from three glacial-related mass redistribution mechanisms using, as an example, the North Sea throughout the Quaternary: (1) ice-sheet loading, (2) erosion, including glacial carving of fjords; (3) and sediment deposition. These processes yielded up to 1 km of vertical displacement of the lithosphere across the North Sea, and the corresponding sediment-tilting changed the geometry of petroleum systems and hydrocarbon migration routes. Using the Base Cretaceous Unconformity as a top seal proxy, we analyse the consequences in the Norwegian North Sea. Comparing well data to models, we suggest that tilting the Troll Field back towards its early Quaternary position flattens the palaeo-oil–water contact (palaeo-OWC), which today is tilted by up to 70 m. The Johan Sverdrup Field shows a more complex history. Hints of a palaeo-OWC tilted can be seen in permeable reservoirs, whereas deeper sporadic oil shows cannot be explained by simple tilt models. Our study illustrates how glacial-related processes may influence the development of giant oil and gas accumulations.

Technology Focus: Multilateral and Complex-Trajectory Wells (May 2019)

Technology Focus When students ask me about the most important way to maximize recovery, my answer is long directional wells. These wells have revolutionized the oil industry and are drilled under conditions never imaginable years ago. One outstanding example is the Troll field in Norway. The field consists of large, very thin reservoirs, down to 30 ft thick, which are drained by multibranch horizontal wells with horizontal departures approaching 18,000 ft. Not only have many drilling challenges been overcome, but also, from a production perspective, the wells are equipped with intelligent technology such as autonomous gas stop to maintain the pressure drive for the oil. Initially of no commercial interest because of a lack of technology, this field has been a very important driver for the current state of the art for long horizontal wells. Troll has been Norway’s largest oil producer in recent years. This has been made possible by the development of long-horizontal-well technology. The oil industry is currently undergoing a technological transformation that will add value, improve processes, and reduce cost. Future drilling engineers will have knowledge of robotics, automation, and organizational efficiency, which is highly appealing for recruitment. A prerequisite for this step change is the industry’s high level of technology. The selected papers address various aspects of horizontal wells. A field case of how to plan and drill through highly depleted reservoirs is given in paper OTC 28517. Three depleted zones must be penetrated before drilling into the untapped reservoir with a low drilling margin. This is a good example of drilling an extended-reach well using an integrated approach between various disciplines. Another example is given in paper SPE 191436, which shows how a complex U-shaped well path from old wells can be used to obtain good reservoir exposure to drain depleted wells further. Equipment is continuously improved, and paper SPE 189947 presents new ultrasonic technology to evaluate the state of multilateral junctions. SPE 191271 Extended-Reach Wells in Unconsolidated Sands in Bolivia by Gabriel Dordoni, Pluspetrol Bolivia OTC 28971 Correlation of Numerical Simulation and Digital-Image-Correlation Strain Measurements for a Multilateral Junction While Subjected to High Internal Pressure by Aihua Liang, Halliburton, et al. SPE 192672 Wireline Tractor Conveyance—A Technology Game Changer for the Gulf of Thailand by Sarunya Jongnarungsin, Mubadala Petroleum, et al.

Effects of Uncertainties in Fault Interpretations on Pressure Depletion and CO2 Storage Injection at Horda Platform, Offshore Norway

Fractures and faults may serve as important barriers or conductors to fluid flow and pressure propagation in the underground. When injecting CO2 into a reservoir for underground storage, the pressure changes in the subsurface can potentially affect large areas, depending on reservoir characteristics and injected volumes and rates. Similarly, production of fluids (i.e. oil and gas production) can have a far-reaching influence on pressure and knowledge about the existence and properties of faults and fractures is important for understanding and controlling pressure in CO2 injection projects. In this paper, we focus on testing how the sealing properties of interpreted faults will affect fluid flow and CO2 injection over production time scale. In particular, we aim to test the effect of the uncertainty in interpretation of relay zones along large fault systems. Simulations have been carried out on a dataset from the Horda Platform and northern part of the Stord Basin, offshore Norway. We address the potential effect of pressure depletion in the Troll oil and gas field on the Smeaheia area which has been considered for CO2 underground storage. This is done by varying the sealing properties of the faults and by testing the effect of assuming extended faults in two relay zones along the N-S striking Vette Fault System. Reservoir simulations show that assuming sealing relay ramp structures will have a major impact on pressure development in the target injection area caused by the pressure depletion in the Troll Field and the injection of 150 Mt CO2 in Smeaheia. With sealing relay zones along the Vette Fault, the pressure in the Smeaheia area will be higher and less affected by the Troll Field depletion, and thereby the gas plume and gas saturation will affect a smaller area, compared to assuming open or semi-sealing faults.

Storing Co2 in a Reservoir Under Continuous Pressure Depletion; a Simulation Study

Norwegian Ministry of Petroleum and Energy commissioned a feasibility study in 2016 to qualify an offshore reservoir for full-scale CCS in Norway. The Smeaheia fault block, a saline aquifer east of the Troll field, was selected as the best alternative among three studied candidates. The Smeaheia CO2 storage prospect is located on the Horda Platform, mainly in Blocks 32/4 and 32/1 on the Norwegian Continental Shelf, east for Troll field. The fault block is shallower than Troll, eliminating the risk of CO2 migration and contaminating the Troll East gas reservoir. The target reservoir for CO2 storage is the Viking group, a 400-meter thick reservoir consisting of the Sognefjord-, Fensfjord- and Krossfjord Formations from top to bottom. Depth of Top Sognefjord varies from around 900 meters in east to around 1300 meters in west close to the Vette fault. Reservoir temperature is expected to vary between 35 to 45 oC depending on the depth. Based on the experience from hydrocarbon production in the Troll field, the Sognefjord and Fensfjord formations generally consist of high permeability and high porosity sands with very good lateral and vertical communication. Although the reservoir quality deteriorates to some extend moving from west to east, the reservoir properties and hence the communication is expected to be as good as in the Troll field. There are two relay ramps cutting the Vette fault with probable sand-sand communication putting the Smeaheia fault block in expected pressure communication with the Troll field. Due to large volumetric production of hydrocarbons from the Troll field, pressure depletion is also expected in the Viking group in Smeaheia fault block in case of pressure communication. In a most likely scenario, Smeaheia is depleted below hydrostatic pressure when CO2 injection starts and pressure will continue to deplete whilst CO2 injection is ongoing. The Smeaheia fault block is, in parts, already on the border of the recommended depth of 800 meters for CO2 storage reservoirs where CO2 is stored as a dense phase. Pressure depletion could cause CO2 stored in shallower parts of the reservoir to convert to gas, resulting in further expansion of gaseous CO2 and hence reducing the ultimate storage capacity of the identified structural traps. A simulation model is developed to study the CO2 movement in storage reservoir and estimate the storage capacity of the Smeaheia fault block under depletion. The structural model is based on the latest seismic interpretation for Smeaheia and the static properties are modelled based on log data from exploration wells on Blocks 32/4 and 32/1. In the absence of pressure measurements, the extent of depletion in Smeaheia as a result of Troll production is inferred from a regional aquifer simulation model. Dummy water producers are used to deplete the model as predicted by the regional model. This paper presents the studies carried out using the developed simulation model to address effects of pressure depletion on CO2 plume movement in Smeaheia. Important decision parameters such as well location, depth of injection, design of the injection well, and number of injectors to increase storage capacity are all affected by the depletion situation in the reservoir. These should be studied thoroughly in order to achieve a cost-effective and robust injection system that ensures the safe storage of CO2 in Smeaheia independent of depletion effects due to Troll production.

Mooring design and selection for floating offshore wind turbines on intermediate and deep water depths

The paper focuses on design and selection of mooring systems for Floating Offshore Wind Turbines (FOWTs) for intermediate and deep water depths, based on ultimate, accidental and fatigue limit state design conditions, with reference to power production, parked wind turbine and mooring line fault conditions. Platform static and dynamic offsets are determined by a purposely developed 6DOF programme in the frequency domain, accounting for first and second order motions. The Dutch tri-floater platform, together with the well-known 5 MW NREL wind turbine, is assumed as reference design. Besides, two sites, the one in the Southern North Sea, near Dogger Bank on water depths ranging from 50 up to 80 m, the other one in the Northern North Sea, near the Troll field area on water depths ranging from 200 up to 350 m, are assumed as candidate deployment areas, to investigate the effect of: (i) line number, (ii) platform admissible offset and line scope, (iii) offshore/onshore planned maintenance inspections and (iv) mooring technology on relevant installation and maintenance costs. A preliminary cost analysis is also performed and some recommendations are given to correctly choice the most suitable mooring configuration, as a function of water depth.

The 35/9-7 Skarfjell discovery: a genuine stratigraphic trap, NE North Sea, Norway

Abstract The Skarfjell oil and gas discovery, situated 50 km north of the Troll Field in the NE North Sea, was discovered by well 35/9-7 and was appraised by three additional wells operated by Wintershall, in the period 2012–14. The Skarfjell discovery is an example of a combined structural/stratigraphic trap. The trap formed along the northern edge of a deep WNW–ESE-trending submarine canyon, which was created by Volgian erosion of intra-Heather, Oxfordian-aged sandstones and then infilled with Draupne Formation shales. This mud-filled canyon forms the top and side seal, with the bottom seal provided by Heather shales. The reservoir comprises mid-Oxfordian deep-water turbidites and sediment gravity flows, which formed in response to tectonic hinterland uplift and erosion of the basin margin, 10–20 km to the east. The Skarfjell discovery contains light oil and gas, and may be subdivided into Skarfjell West, in which the main oil reservoir and gas cap have known contacts, and Skarfjell Southeast, which comprises thinner oil and gas reservoirs with slightly lower pressure and unknown hydrocarbon contacts. The Upper Jurassic Draupne and Heather formations are excellent source rocks in the study area. They have generated large volumes of oil and gas reservoired in fields, and discoveries for which the dominant source rock and its maturity have been established by oil to source rock correlation and geochemical biomarker analysis. The Skarfjell fluids were expelled from mid-mature oil source rocks of mixed Heather and Draupne Formation origin. The recoverable resources are estimated at between 9 and 16 million standard cubic metres (Sm 3 ) of recoverable oil and condensate, and 4–6 billion Sm 3 of recoverable gas. The Skarfjell discovery is currently in the pre-development phase and is expected to come on stream in 2021.

A hybrid finite-difference and integral-equation method for modeling and inversion of marine controlled-source electromagnetic data

One of the major problems in the modeling and inversion of marine controlled-source electromagnetic (CSEM) data is related to the need for accurate representation of very complex geoelectrical models typical for marine environment. At the same time, the corresponding forward-modeling algorithms should be powerful and fast enough to be suitable for repeated use in hundreds of iterations of the inversion and for multiple transmitter/receiver positions. To this end, we have developed a novel 3D modeling and inversion approach, which combines the advantages of the finite-difference (FD) and integral-equation (IE) methods. In the framework of this approach, we have solved Maxwell’s equations for anomalous electric fields using the FD approximation on a staggered grid. Once the unknown electric fields in the computation domain of the FD method are computed, the electric and magnetic fields at the receivers are calculated using the IE method with the corresponding Green’s tensor for the background conductivity model. This approach makes it possible to compute the fields at the receivers accurately without the need of very fine FD discretization in the vicinity of the receivers and sources and without the need for numerical differentiation and interpolation. We have also developed an algorithm for 3D inversion based on the hybrid FD-IE method. In the case of the marine CSEM problem with multiple transmitters and receivers, the forward modeling and the Fréchet derivative calculations are very time consuming and require using large memory to store the intermediate results. To overcome those problems, we have applied the moving sensitivity domain approach to our inversion. A case study for the 3D inversion of towed streamer EM data collected by PGS over the Troll field in the North Sea demonstrated the effectiveness of the developed hybrid method.