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Collaborating Authors
Dutch Sector
ABSTRACT Seismic facies mapping from a 3D seismic cube is of significant value to various seismic interpretation and characterization tasks. Traditional facies mapping is based on examining sedimentary environments and stratigraphic sequences that provide distinct characteristics used for facies mapping. Given the complex nature of the task, manual facies mapping is typically time and labor consuming, and the quality of the decisions varies as a function of expertise. This complexity is further increased with the ever-increasing size of 3D seismic data sets. Deep-learning methods have indicated a promising potential to perform fast, accurate, and automated segmentation tasks. We investigate the application of machine-learning techniques, particularly state-of-the-art deep convolutional neural networks (CNNs), as a framework to perform accurate automated seismic facies pixel-wise segmentation. The workflow consists of a CNN-based U-Net architecture that adopts modern computer vision techniques. We develop three major changes to the standard U-Net to boost the performance for seismic semantic segmentation tasks: (1)ย using residual building blocks in the encoder, (2)ย using transformer-like attention gates after each residual block, and (3)ย using frequency spectrum data, in addition to seismic amplitude, as input to the network. We indicate that this implementation achieves higher accuracy metrics outperforming recently published state-of-the-art benchmarks. The performance of our method is validated using two 3D seismic data sets, the F3 Netherlands data set and the Penobscot data set acquired offshore Nova Scotia, Canada. Experimentation involves training on a set of samples and tuning the hyperparameters, followed by quantitative evaluation of the trained network. Our workflow produces high-quality segmentation with significantly reduced artifacts, improved edge detection, and improved lateral consistency throughout the seismic survey.
- Europe (0.53)
- North America > Canada > Nova Scotia (0.34)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.87)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- North America > Canada > Newfoundland and Labrador > Newfoundland > Nova Scotia > North Atlantic Ocean > Atlantic Margin Basin > Scotian Basin (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > North Atlantic Ocean > Atlantic Margin Basin > Scotian Basin (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > B16-01 License > Upper North Sea Group (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Neural networks (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
ABSTRACT Seismic facies mapping from a 3D seismic cube is of significant value to various seismic interpretation and characterization tasks. Traditional facies mapping is based on examining sedimentary environments and stratigraphic sequences that provide distinct characteristics used for facies mapping. Given the complex nature of the task, manual facies mapping is typically time and labor consuming, and the quality of the decisions varies as a function of expertise. This complexity is further increased with the ever-increasing size of 3D seismic data sets. Deep-learning methods have indicated a promising potential to perform fast, accurate, and automated segmentation tasks. We investigate the application of machine-learning techniques, particularly state-of-the-art deep convolutional neural networks (CNNs), as a framework to perform accurate automated seismic facies pixel-wise segmentation. The workflow consists of a CNN-based U-Net architecture that adopts modern computer vision techniques. We develop three major changes to the standard U-Net to boost the performance for seismic semantic segmentation tasks: (1)ย using residual building blocks in the encoder, (2)ย using transformer-like attention gates after each residual block, and (3)ย using frequency spectrum data, in addition to seismic amplitude, as input to the network. We indicate that this implementation achieves higher accuracy metrics outperforming recently published state-of-the-art benchmarks. The performance of our method is validated using two 3D seismic data sets, the F3 Netherlands data set and the Penobscot data set acquired offshore Nova Scotia, Canada. Experimentation involves training on a set of samples and tuning the hyperparameters, followed by quantitative evaluation of the trained network. Our workflow produces high-quality segmentation with significantly reduced artifacts, improved edge detection, and improved lateral consistency throughout the seismic survey.
- Europe (0.53)
- North America > Canada > Nova Scotia (0.34)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.87)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- North America > Canada > Newfoundland and Labrador > Newfoundland > Nova Scotia > North Atlantic Ocean > Atlantic Margin Basin > Scotian Basin (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > North Atlantic Ocean > Atlantic Margin Basin > Scotian Basin (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > B16-01 License > Upper North Sea Group (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Neural networks (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Bastiaan (Bas) Baars was a geophysicist with Shell, where in 1957 he was head of geophysical services. After World War II he was mainly concerned with seismic techniques. He was co-founder of the European Association of Exploration Geophysicists (EAEG) which later became the European Association of Geoscientists and Engineers (EAGE). He retired in 1967, after which he was active in the German company PRAKLA (geophysical services). It is not often that the Committee on Honors and Awards together with the Executive Committee reaches across the ocean to bestow the Society's highest honor on one of its members and this only adds to the luster of the Honorary Membership awarded to Dr. Bastiaan Baars.
- Europe (0.32)
- North America > United States > Texas > Harris County > Houston (0.16)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Alkali Polymer Flooding: Tackling Risks and Challenges from Feasibility Study to Pilot
Janczak, A. (OMV Exploration & Production GmbH, Vienna, Austria) | Hincapie, R. E. (OMV Exploration & Production GmbH, Vienna, Austria) | Grottendorfer, S. (OMV Exploration & Production GmbH, Vienna, Austria) | Schrรถckenfuchs, T. (OMV Exploration & Production GmbH, Vienna, Austria)
Abstract Alkali Polymer (AP) is considered as enhanced oil recovery (EOR) technique for a mature field in Austria. To achieve technology qualification, different workflows have been implemented that supports risks definition and mitigations. We therefore present here the necessary steps utilized for the AP technology development and qualification. We evaluate challenges including laboratory assessments, subsurface and surface elements, aiming at demonstrating the effectiveness of AP to produce additional oil and to enable a field pilot. Multidisciplinary work packages allowed creating a holistic understanding of the benefits and challenges of AP injection and mitigate these challenges to enable a field pilot. Laboratory experiments were performed to determine an effective recipe to mobilize oil without detrimental reservoir interaction (rheology measurements, phase behavior tests, core floods etc.). The design of the pilot facilities built on water softening technologies tests. Finally key producers were identified based on previous tracer and polymer breakthrough results, and workovers were planned to allow implementing scaling mitigation solutions. A partitioning tracer test was also carried out to measure the remaining oil before AP pilot. The selected recipe showed significant residual oil mobilization, recovery factor increases and low polymer adsorption. Aging experiments showed that polymer hydrolysis in the reservoir in alkaline conditions allowed using lower polymer concentration and facilitate injectivity. Facilities design centered around keeping pilot costs as low as possible, by reusing existing polymer dosing and mixing facilities, and designing an additional alkali dosing and mixing plant. To mitigate the risk of precipitation at the injector, the water treatment was upgraded to remove divalent ions before mixing with alkali. Pre-qualification tests under field conditions allowed developing and optimizing a weak acid cation exchanger unit meeting operational requirements. This process was then engineered at the pilot scale and implemented in the AP pilot project. Finally, wells were evaluated to ensure material compatibility with AP fluids, and 3 producers with high expected alkaline back-produced concentration were selected for a workover allowing retrofitting a scale inhibition string. The scale inhibitor was selected using a dynamic scale loop. In conclusion, all work packages performed enable carrying out a field pilot with reduced risk. Starting Q2 2023, the pilot will focus on gaining operational experience with the new facilities, as well as scaling and emulsions mitigation solutions. While the industry saw multiple Alkaline, Surfactant and Polymer floods, Alkali and Polymer has only limited literature. However, by avoiding costs linked to surfactant, AP appears as an attractive EOR technique for highly reactive oils. This work presents the steps carried out to obtain understanding of the potential oil gains, and evaluate injectivity, scaling and emulsions risks. The methodology allowed de-risking the technology and bringing it from the laboratory to the field with a pilot.
- North America > United States (1.00)
- Asia > Middle East (1.00)
- Europe > Austria (0.89)
- Europe > United Kingdom > North Sea > Central North Sea (0.75)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.66)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.54)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- (6 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Abstract Petroleum Systems Modeling is a well-known workflow to evaluate the basin potential. However, in the prospect maturation stage, we mainly focus on reservoir and trap characterization. The lack of an established workflow to quantify the risks associated with seal integrity and preferred migration, is one of the main reasons for dry wells. This establishes an innovative workflow and explores the value of coupling the regional scale insights into a prospect specific study in a field with existing discovery for exploration risk mitigation. An integrated fluid migration approach has been adopted to de-risk the prospect and predict the likely migration pathway in the petroleum system. This integrated workflow consists of detailed reservoir scale characterization using advanced seismic attributes, followed by static and dynamic migration simulation to envisage the local migration process within a high-resolution reservoir model to assess the sealing capacity of the cap rock. A modified invasion percolation method has been used to evaluate the effect of buoyancy and capillary pressure driven hydrocarbon fluid migration in the high-resolution reservoir model and in turn, inspect the seal integrity to withhold the hydrocarbon column height. The fluid migration model was simulated with a multi-phase PVT model to estimate the hydrocarbon phase at the reservoir condition. A fluid mixing model was also built at the prospect scale to evaluate the fluid phase and composition understanding. This helped in estimating fluid distribution in the field scale in terms of phase and components of hydrocarbon. The seal integrity model involves detailed assessment of the PVT model along with wettability and interfacial tension of the rock properties for accurate prediction of the column height holding capacity. The model has been calibrated with the existing well data and production data in terms of hydrocarbon saturation and the tested fluid phase at the production well. This novel approach can be positioned as an advanced quantification tool in prospect focused imaging where the risk parameters relating to migration and cap rock are also being evaluated without losing any information from the regional context. This new way of de-risking process can help to mitigate the potential risks associated with the petroleum systems elements to increase exploration success.
- Europe > United Kingdom > North Sea (0.49)
- North America > United States > Kansas > Sheridan County (0.40)
- Europe > Norway > North Sea (0.31)
- Europe > Netherlands > North Sea (0.31)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock (0.97)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin (0.99)
- Europe > United Kingdom > North Sea > North Sea Basin (0.99)
- Europe > Poland > North Sea > Southern North Sea > Southern Gas Basin (0.99)
- (6 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.91)
Summary The author describes the method and results of a global and automated approach for seismic interpretation (Pauget et al, 2009), applied to a pre-salt gas field of the Dutch Cleaver Bank High platform, offshore Netherlands. A sequence stratigraphic framework called โRelative Geological Time (RGT) modelโ is built from the seismic data to emphasize structural and stratigraphic features. Basin and reservoir characterizations are thus enabled by RGT-derived advanced attributes, rock physics modelling, Wheeler diagrams and sub-sample stratal slicing. Several fault networks related to different tectonic phases are emphasized, key stratigraphic surfaces are delineated, and major facies trends of the pre-salt reservoir level are discriminated. Those outputs are finally used to assess the impact of fault networks and subsequent subsidence on the eustasy-controlled thin beds succession. The author ultimately demonstrates the potential of the global RGT modelling method to revise hydrocarbon fields and identify pre-salt siliciclastic carbon storage sites.
- Europe > Netherlands (0.76)
- North America > United States (0.69)
- Phanerozoic > Paleozoic > Permian (1.00)
- Phanerozoic > Paleozoic > Carboniferous > Pennsylvanian (0.70)
- Phanerozoic > Mesozoic > Triassic (0.69)
- Geology > Structural Geology > Tectonics > Salt Tectonics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Abstract CO2 injection into depleted gas fields causes long-term cooling of the reservoir. Therefore, even if injection pressure stays below the fracture initiation pressure, the cooled volume still creates an extensive stress disturbance that can induce propagation of large fractures over time. The enhanced injectivity after the onset of this thermal fracturing might jeopardize injection operations due to the risk of hydrate plugging in the injection well caused by the combination of low pressure and low temperature, and large fractures may also increase the risk of loss of containment. Modeling the fracture evolution provides an estimate of these effects and their timing. Coupled simulation of CO2 injection provides the thermal fracture dimensions for a given uncertainty in the reservoir parameters. Simplified stress modelling is applied in the thermal fracture reservoir simulation, but a full 3D geomechanical model that was developed for fault slip analysis provides accurate estimates of the stress state after depletion and the subsequent evolution of the stresses during CO2 injection. For computation efficiency, sector models were used with locally refined grids to accommodate fractures in the reservoir simulation model. It was verified that the fracture models match the full-field simulation under matrix flow conditions. The fracture simulations were developed in close relation with flow assurance modeling to determine the operational windows that avoid hydrate formation while maintaining the required injection target. Thermal fracture propagation by CO2 injection into the depleted Dutch offshore gas field has been simulated by using coupled simulation approach. The model has been developed with geomechanical properties and stresses obtained from various sources in neighboring fields. It was found that stress, thermal expansion coefficient, modulus and permeability distribution are the principal parameters that determine fracture growth. The forecast of thermal fracture propagation yielded in some cases very long fractures reaching compartment boundaries. Injectivity was enhanced by up to a factor of 4, which is significant for flow assurance. The coupled modeling of thermal fracturing provides mitigating measures in case the temperature and pressure drop into the hydrate formation window.
- Europe > Netherlands > North Sea > Dutch Sector > Q10a License > Volpriehausen Formation (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > L09 License > Hardegsen Formation (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > P18a License > P18-4 Field > Main Buntsandstein Formation (0.94)
- (2 more...)
Abstract In two planned large-scale CCS projects in the Netherlands โ Porthos and Aramis โ depleted gas fields will be used for CO2 storage. These fields are characterized by low reservoir pressures. For example, the Porthos project is planned to inject into a field with a reservoir pressure below 20 bar. Project design and operational philosophy need to be specifically tailored to the storage reservoir properties in order to avoid excessively low temperatures when injecting into such fields. This paper describes how these challenges were addressed for the Porthos project. In most CCS projects, a CO2 mixture is transported in a surface network at high pressure and ambient temperature and injected into an aquifer. At the high reservoir pressure typical of aquifer storage the CO2 stream remains in dense phase or supercritical conditions in the entire system. This dense phase transport strategy is not feasible for the P18 field since the bottomhole pressure (BHP) is around 25 bar at the required injection rates. At this low pressure, CO2 will exist in two-phase conditions which results in very low temperatures of โ10 ยฐC. These low temperatures are unacceptable since they may result in hydrate formation in the reservoir and well integrity issues. A specific operating philosophy and project design was developed to avoid unacceptably low temperatures. At a reservoir pressure below 50 bar, CO2 is injected in gas phase in the pipeline and wells. Once the reservoir reaches a pressure of 50 bar the pipeline pressure is increased to 85 bar to achieve dense phase conditions. The well is operated in two-phase conditions but due to the higher BHP well temperatures are now acceptable. However, if CO2 is transported at ambient temperature the injection flow range per well is very narrow and the required project injection range cannot be met. This is addressed by using the heat of compression to heat the CO2 stream and insulating the pipeline to achieve elevated arrival temperature. Without these specific choices, safe injection into the P18 field would not have been possible.
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Sleipner Vest Field > Sleipner Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Sleipner Vest Field > Hugin Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Sleipner Vest Field > Draupne Formation (0.99)
- (59 more...)
Hydrogen Storage in Depleted Gas Fields: A North Sea Case Study
Looijer, M. (Shell Global Solutions International B.V., The Hague, The Netherlands) | Ahmad, I. (Shell India Markets Private Ltd, Bangalore, India) | Kathel, P. (Shell Global Solutions International B.V., The Hague, The Netherlands) | Filomena, C. (Shell Global Solutions International B.V., The Hague, The Netherlands) | de Borst, K. (Shell Global Solutions International B.V., The Hague, The Netherlands)
Abstract This paper presents a case study on a near-shore gas field in the Dutch North Sea for a seasonal storage scenario. A subsea development was considered, connected by pipeline to an onshore processing facility. Reservoir simulations were carried out to model the mixing of the hydrogen with the in-situ natural gas and to estimate the composition of the back-produced stream and its variation during and between the individual cycles. The required sizing of the processing facilities was determined through process models, and the pipeline sizing through a hydraulic assessment. The development considered new wells, which were designed to deliver the assumed hydrogen production rate at the end of a production cycle when contamination is highest. The investment and operational costs of the complete facility were estimated as well as emissions of the storage operations. The study enhanced the understanding of the technical scope and technology gaps; as well as the economic, environmental, and energy performance of underground hydrogen storage. It highlights main cost drivers and delivers insights into the re-purposing potential of the existing infrastructure. An example insight gained from the study was that the disposal (or utilization) of the waste stream from gas separation could pose a real challenge particularly in an offshore environment, given its intermittent character, the highly variable and partly unpredictable composition, its large flow rate, and its near-atmospheric pressure when using a Pressure Swing Adsorber for separation.
- Geology > Geological Subdiscipline (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.46)
- Europe > Netherlands > North Sea > Dutch Sector > West Netherlands Basin (0.99)
- Europe > Germany (0.89)
Hybrid Uses of High-Temperature Reservoir Thermal Energy Storage: Lessons Learned from Previous Projects
Dobson, P. F. (Energy Geosciences Division, Lawrence Berkeley National Laboratory, Berkeley, CA, USA) | Atkinson, T. A. (Idaho National Laboratory, Idaho Falls, ID, USA) | Jin, W. (Idaho National Laboratory, Idaho Falls, ID, USA) | Acharya, M. (Idaho National Laboratory, Idaho Falls, ID, USA) | Akindipe, D. (National Renewable Energy Laboratory, Golden, CO, USA) | Li, B. (Idaho National Laboratory, Idaho Falls, ID, USA) | McLing, T. (Idaho National Laboratory, Idaho Falls, ID, USA) | Kumar, R. (Energy Geosciences Division, Lawrence Berkeley National Laboratory, Berkeley, CA, USA)
Abstract One of the critical challenges of the green energy transition is resolving the mismatch between energy generation provided by intermittent renewable energy sources such as solar and wind and the demand for energy. There is a need for large amounts of energy storage over a range of time scales (diurnal to seasonal) to better balance energy supply and demand. Subsurface geologic reservoirs provide the potential for storage of hot water that can be retrieved when needed and used for power generation or direct-use applications, such as district heating. It is important to identify potential issues associated with high-temperature reservoir thermal energy storage (HT-RTES) systems so that they can be mitigated, thus reducing the risks of these systems. This paper reviews past experiences from moderate and high-temperature reservoir thermal energy storage (RTES) projects, along with hot water and steam flood enhanced oil recovery (EOR) operations, to identify technical challenges encountered and evaluate possible ways to address them. Some of the identified technical problems that have impacted system performance include: 1) insufficient site characterization that failed to identify reservoir heterogeneity; 2) scaling resulting from precipitation of minerals having retrograde solubility that form with heating of formation brines; 3) corrosion from low pH or high salinity brines; 4) thermal breakthrough between hot and cold wells due to insufficient spacing. Proper design, characterization, construction, and operational practices can help reduce the risk of technical problems that could lead to reduced performance of these thermal energy storage systems.
- Europe > Germany (1.00)
- Asia > Middle East (1.00)
- North America > United States > California (0.68)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Renewable > Geothermal (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Badejo-Siri Field > Siri Field (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > Leeuwarden License > Ommelanden Formation (0.99)
- Europe > Netherlands > German Basin (0.99)
- (3 more...)