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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.
The objective of this paper is to show the value of using real time remote monitoring system (Automation) in offshore wells and to show a case study from Company for how we successfully used the system to detect well anomalies in real time and perform the suitable corrective action to optimize the well production and maximize well recovery with minimum man-hours.
Our company is a leading Egyptian petroleum company with + 200 oil producers on 70 offshore platform; 27 % of platforms include automation system, in platforms without automation system we detect wells problems by performing periodic site visits and check the operating parameters per well., normally it take weeks between two successive platform visits. For platforms with automation system, we install pressure sensors on WH, Manifold, and casing head and temperature sensor on WH., The data being transferred from sensors to office instantaneously, which we successfully made use of, to respond quickly to the problems and achieved maximum well recovery.
The offshore oil producer well J-100 was drilled and put on production on Nov. 2015, the well was producing naturally from the attic of the reservoir, it was a mandatory to control the production rate to keep the well producing beyond the calculated critical production rate to avoid water coning. After a while of putting the well on production, well sensors showed several successive abnormal changes in readings which had been captured in real time with the help of automation system, and with data analyzing we found the causes of each phenomena every time (like loading up, a problem in the production choke, etc.) and we succeeded to prepare the action plan, and perform the scope of work as soon as possible. Without the automation system, it would take weeks to detect the problem based on the site visits plan. However, installing the automation system will enhance the response efficiency by saving the time required for problem detection, and improving the quality, density and accuracy of well data. In addition, it will decrease the losses in production rate, and maximize the recovery by optimizing the production rate based on the field depletion plan.
In summary, this paper discussing a case study for the value of using real time remote monitoring systems in offshore fields and we used this case to highlight the need to expand the system to include more wells in our field to maximize the field recovery and add considerable benefit to the business.
Pfeiffer, Thomas (Schlumberger) | Sarili, Mahmut (Schlumberger) | Wang, Cong (Schlumberger) | Naito, Koichi (Schlumberger) | Morikami, Yoko (Schlumberger) | Chen, Hua (Schlumberger) | Shabibi, Hamed (Petroleum Development Oman) | Frese, Daniela (Petroleum Development Oman)
For every barrel of oil, about three to four barrels of water is produced. Water is part of every operation in upstream oil and gas: we produce it, we process it, we inject it. It affects our reserves because it may drive or sweep the oil out of the pores. It is a source of corrosion and scaling in pipe and in the reservoir. Measuring formation water resistivity (Rw) goes beyond using it as the basis of petrophysical well log interpretation. It is the key to telling different waters apart for taking the most representative samples.
We introduce a calibrated induction-based water resistivity measurement sensor, which is configured to accurately measure Rw in the flowline of a formation testing tool. The induction-based operating principle of the sensor eliminates the use of electrodes and the associated fouling of the measurement due to coating or accumulation of particles on the electrodes. Instead, the sensor induces an electric current through a nonconductive, neutrally wetting flowline tube that is proportional to the conductivity of the fluid column within the tube. The resulting current at the receiver coil is then converted into resistivity.
A case study presents data from a focused water-sampling station in a transition zone in a well drilled with water-based mud (WBM). The resistivity contrast between the mud filtrate and the formation water is low and mobile oil mixes with the formation water and mud filtrate. Despite these difficult conditions, the downhole measurement clearly shows the cleanup progress in real time and compares well with the surface measurements of the water samples. The ability to differentiate formation water from WBM filtrate with low resistivity contrast in the presence of oil places the station depth in the transition zone and enables accurate interpretation of contacts, saturation, and ultimately hydrocarbon in place.
The sensor package is suitable for use up to 200-degC temperature and 35,000-psi pressure. The sensor can measure a wide range of resistivity, from 0.01 to 65 ohm.m. Measurements performed on known fluids prove its high accuracy of ±5% or less for resistivity below 10 ohm.m at a resolution of 0.001 ohm.m. The design eliminates any dead volume and all flowline fluid passes through the sensor. The sensor tube is smoothly flushable for fast dynamic response in multiphase slug flow.
This paper also discusses optimal sensor placement and operational techniques to achieve best results in multiphase flow environments.
The accuracy and resolution of the resistivity measurement enables direct comparison of guard and sample flowlines during focused sampling and provides differentiation even when the contrast between filtrate and formation water is low. The results can serve as a direct Rw measurement, for example in an exploration scenario, as successfully shown in another PDO trial, or can be compared to other sources of Rw measurement or used to improve the accuracy of alternatives to the Archie equation, such as dielectric dispersion.
Rücker, Maja (Imperial College London / Shell Global Solutions International B.V.) | Bartels, Willem-Bart (Utrecht University / Shell Global Solutions International B.V.) | Bultreys, Tom (Imperial College London / Ghent University) | Boone, Marijn (Tescan XRE) | Singh, Kamaljit (Heriot-Watt University / Imperial College London) | Garfi, Gaetano (Imperial College London) | Scanziani, Alessio (Imperial College London) | Spurin, Catherine (Imperial College London) | Yesufu-Rufai, Sherifat (Imperial College London) | Krevor, Samuel (Imperial College London) | Blunt, Martin J. (Imperial College London) | Wilson, Ove (Shell Global Solutions International B.V.) | Mahani, Hassan (Shell Global Solutions International B.V.) | Cnudde, Veerle (Utrecht University / Ghent University) | Luckham, Paul F. (Imperial College London) | Georgiadis, Apostolos (Imperial College London / Shell Global Solutions International B.V.) | Berg, Steffen (Imperial College London / Utrecht University)
Wettability is a key factor influencing multiphase flow in porous media. In addition to the average contact angle, the spatial distribution of contact angles throughout the porous medium is important, as it directly controls the connectivity of wetting and nonwetting phases. The controlling factors may not only relate to the surface chemistry of minerals but also to their texture, which implies that a length-scale range from nanometers to centimeters has to be considered. So far, an integrated workflow addressing wettability consistently through the different scales does not exist. In this study, we demonstrate that such a workflow is possible by combining microcomputed tomography (μCT) imaging with atomic-force microscopy (AFM). We find that in a carbonate rock, consisting of 99.9% calcite with a dual-porosity structure, wettability is ultimately controlled by the surface texture of the mineral. Roughness and texture variation within the rock control the capillary pressure required for initializing proper crude oil-rock contacts that allow aging and subsequent wettability alteration. AFM enables us to characterize such surface-fluid interactions and to investigate the surface texture. In this study, we use AFM to image nanoscale fluid-configurations in 3D at connate water saturation and compare the fluid configuration with simulations on the rock surface, assuming different capillary pressures.
Berg, Steffen (Shell Global Solutions International B.V. / Imperial College London) | Gao, Ying (Shell Global Solutions International B.V. / Imperial College London) | Georgiadis, Apostolos (Shell Global Solutions International B.V. / Imperial College London) | Brussee, Niels (Shell Global Solutions International B.V.) | Coorn, Ab (Shell Global Solutions International B.V.) | van der Linde, Hilbert (Shell Global Solutions International B.V.) | Dietderich, Jesse (Shell International Exploration and Production Inc.) | Alpak, Faruk Omer (Shell International Exploration and Production Inc.) | Eriksen, Daniel (Shell Global Solutions International B.V.) | Mooijer-van den Heuvel, Miranda (Shell Global Solutions International B.V.) | Southwick, Jeff (Shell Global Solutions International B.V.) | Appel, Matthias (Shell Global Solutions International B.V.) | Wilson, Ove Bjørn (Shell Global Solutions International B.V.)
The critical gas saturation was directly determined using micro-CT flow experiments and associated image analysis. The critical gas saturation is the minimum saturation above which gas becomes mobile and can be produced. Knowing this parameter is particularly important for the production of an oil field that during its lifetime falls below the bubblepoint, which will reduce the oil production dramatically. Experiments to determine the critical gas saturation are notoriously difficult to conduct with conventional coreflooding experiments at the Darcy scale. The difficulties are primarily related to two effects: The development of gas bubbles is a nucleation process which is governed by growth kinetics that, in turn, is related to the extent of pressure drawdown below the bubblepoint. At the Darcy scale, the critical gas saturation at which the formed gas bubbles connect to a percolating path, is typically probed via a flow experiment, during which a pressure gradient is applied. This leads not only to different nucleation conditions along the core but also gives no direct access to the size and growth rate of gas bubbles before the percolation. In combination, these two effects imply that the critical gas saturation observed in such experiments is dependent on permeability and flow rate, and that the critical gas saturation relevant for the (equilibrium) reservoir conditions has to be estimated by an extrapolation. Modern digital-rock-related experimentation and modeling provides a more elegant way to determine the critical gas saturation. We report pressure-depletion experiments in minicores imaged by X-ray computed microtomography (micro-CT) that allowed the direct determination of the connectivity of the gas phase. As such, these experiments enabled the detection of the critical gas saturation via the percolation threshold of the gas bubbles. Furthermore, the associated gas- and oil relative permeabilities can be obtained from single-phase flow simulations of the connected pathway fraction of gas and oil, respectively.
Gamma ray measurements have been made while drilling since the late 1970s. These measurements are relatively inexpensive, although they require a more sophisticated surface system than is needed for directional measurements. Log plotting requires a depth-tracking system and additional surface computer hardware. Applications have been made in both reconnaissance mode, where qualitative readings are used to locate a casing or coring point, and evaluation mode. Verification of proper measurement while drilling (MWD) gamma ray detector function is normally performed in the field with a thorium blanket or an annular calibrator.
Segura, Jordi (Schlumberger) | Trummer, Sascha (Schlumberger) | Grisanti, Maria (Schlumberger) | Varkey, Joseph (Schlumberger) | McCabe, Jeff (Schlumberger) | Hofacker, Mark (Schlumberger) | Fancio, Caio (Schlumberger) | Pathak, Devesh (Schlumberger) | Keong, Azwan (Schlumberger) | Vingen, Sindre (Schlumberger)
This study presents the evolution of downhole fiber optics to a new hybrid electro-optical cable for coiled tubing (CT) applications. The optical fibers enable optical communication and distributed measurements such as distributed temperature and acoustic sensing. The electrical layer delivers continuous surface power to downhole tools, eliminating typical battery limitations such as temperature, operating time, and safety concerns. The electrical layer also enables cable telemetry operation of wireline tools.
The hybrid cable is composed of several layers: an inner tube protecting the optical fibers, a layer of low-DC-resistance conductors to deliver high voltage downhole, an insulator, and an outer tube that is exposed to the fluids in the CT pipe. This complex cable is packaged with an outer diameter of only 1/8 in. to maintain maximum flow rates achievable through the pipe. Surface and downhole equipment used with the cable are designed to accommodate electro-optical terminations separating the conductors and optical lines.
The cable has been manufactured, tested, and installed in CT pipes. The surface and downhole equipment has been designed and certified to operate in both land and offshore environments and tested with multiple families of tools: well intervention tools instrumented with pressure, temperature, depth control, and load sensors; wireline tools, including pulsed neutron generator and flow profiling tools; a multilateral re-entry tool; and an electrically actuated multiple-set retrievable plug.
Over 20 runs and 1,000 hours of operation have already been completed without any power or telemetry loss. The system has saved 160 hours of operation time in Middle East from the implementation of the hybrid cable single-reel solution on four jobs that formerly required two CT strings. In the Norwegian continental shelf, the system saved between 24 hours and 32 hours in a single job by eliminating trips to surface to replace the batteries.
This new hybrid cable and its associated surface and downhole system provide a single solution for interventions, distributed measurements, and logging. Altogether, they pave the way for significant improvements in well intervention efficiency and open new avenues for more complex and demanding operational workflows.
Summary The use of advanced solid-state gyroscopic sensors has become both a viable and practical option for high-accuracy wellbore placement, with the potential to outperform traditional mechanical gyroscopic systems. In this paper, we describe how the contributions of the new gyroscope technology are causing service providers to reconsider current survey practices, and to examine how the new gyroscopic-survey tools can best be used for wellbore surveying and real-time wellbore placement. The simultaneous application of multiple survey tools, largely made possible as a result of the unique attributes of solid-state gyroscopic sensors (including small size and significant power reduction), has clear benefits in terms of enhanced well placement, reliability, and the detection of gross errors in the survey process. Further advantages accrue through the combination of different but complementary survey methods. In this paper, we focus mainly on the benefits of combining gyroscopic and magnetic measurements to reduce or remove the known errors related to the Earth's magnetic field to which magnetic-survey systems are susceptible: errors in total magnetic field, declination, and dip angle. In this context, the use of statistical estimation techniques depending on the performance models of the survey systems used is described. For post-drilling surveys (using drop-survey tools or wireline-conveyed tools, for example), post-run analysis of the data using least-squares estimation techniques is appropriate. Alternative methods capable of achieving real-time data correction during drilling are also described, and results are presented to demonstrate the potential for enhanced magnetic-survey performance. The principles described can be used when running basic magnetic measurement-while-drilling (MWD) systems and for systems that use field correction methods, such as the various infield referencing (IFR) techniques, that are frequently used. The proposed methodology is of particular benefit in the former case, allowing enhanced magnetic surveying to be achieved without the need for expensive and complex magnetic-field correction procedures.
The electromagnetic-wave resistivity (EWR) tool has become the standard of the logging while drilling (LWD) environment. Historically the earliest LWD electromagnetic measurements were Toroidal ( The Arps system of the 1960's ) and Short Normal and Laterolog measurements  of the late 1970's Exlog systems. However technical and mechanical survival considerations quickly caused the 2 Mhz systems to dominate, and these were then expanded with other frequencies.The nature of the electromagnetic measurement requires that the tool typically be equipped with a loop antenna that fits around the OD (outer diameter) of the drill collar and emits electromagnetic waves between slots of a steel protective shroud, which enables a robust mechanical design. The waves travel through the immediate wellbore environment, and are detected by a pair of receivers. Two types of wave measurements are performed at the receivers.