Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Summary Giant reservoirs such as Lula (Santos Oil Basin, Brazil) and Ghawar (Saudi Arabia) have high-permeability intervals, known as super-k zones, associated with thin layers. Modeling these small-scale flow features in large-scale simulation models is difficult. Current methods are limited by high computational costs or simplifications that mismatch the representation of these features in simulation gridblocks. This work has two purposes: present an upscaling work flow to integrate highly laminated or interbedded reservoirs with thin, highly permeable layers in reservoir simulations through a combination of an explicit modeling of super-k layers using the Parsons (1966) formula and dual-medium flow models, and compare this method with two conventional upscaling approaches that are available in commercial software. We use the benchmark model UNISIM-II-R (Correia et al. 2015a), a fine single-porosity grid dependent on field information from the Brazilian presalt and Ghawar oil fields, as the reference solution to compare the upscaling matching between the three methods. We compare oil recovery factor (ORF), water cut (WC), average reservoir pressure (RP), water front, and the time consumption for simulation. Our proposed Parson's dual-medium (PDP) methodology achieved better upscaling matches with the reference model and had minimal time consumption compared with the representation of super-k layers through an implicit matrix modeling by single-porosity flow models (IMP) and through the explicit representation of super-k zones in the fracture system of dual-medium flow models (DFNDP).
- North America > United States (1.00)
- South America > Brazil (0.89)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate (0.34)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.46)
- Geology > Structural Geology > Tectonics > Salt Tectonics (0.34)
- South America > Brazil > Brazil > South Atlantic Ocean > Santos Basin (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.94)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.94)
- (5 more...)
Abstract Giant reservoirs such as Lula (Santos Oil Basin, Brazil) and Ghawar (Saudi Arabia) have high permeability intervals, known as super-k zones, associated with thin layers. Modeling these small-scale flow features in large-scale simulation models is complex. Current methods are limited by high computational costs or simplifications that mismatch the representation of these features in simulation grid blocks. This work has two purposes: (1) present an upscaling workflow to integrate highly laminated or inter-bedded reservoirs with thin, highly permeable layers in reservoir simulations through a combination of (a) an explicit modeling of super-k layers using Parsons (1966) formula and (b) dualmedium flow models, and (2) compare this method with two conventional upscaling approaches, available in commercial software. We use the benchmark model UNISIM-II-R, a fine single-porosity grid based on field information from the Brazilian Pre-salt and Ghawar oil fields, as the reference solution to compare the upscaling matching between the three methods. We compare; oil recovery, water cut, average reservoir pressure, waterfront, and the time consumption for simulation. Our proposed parsons dual-medium (PDP) methodology achieved better upscaling matches with the reference model and had minimal time consumption when compared with the representation of super-k layers through an implicit matrix modelling by single porosity flow models (IMP) and through the explicit representation of super-k zones in the fracture system of dual-medium flow models (DFNDP).
- North America > United States (1.00)
- South America > Brazil (0.89)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate (0.34)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.46)
- Geology > Structural Geology > Tectonics > Salt Tectonics (0.35)
- South America > Brazil > Brazil > South Atlantic Ocean > Santos Basin (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.94)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.94)
- (5 more...)
Abstract Smørbukk is an oil and gas condensate field, part of the Åsgard development in the Norwegian Sea in Norway. The field consists in a vertical succession of various reservoirs of Jurassic age. Most of these reservoirs are layer cake, with sand bodies with several kilometers of horizontal extension versus only a few meters thickness. Lower Tilje formation consists of a volatile oil with a liquid rich gas cap. The development scheme consists in two phases:A gas cycling period, currently taking place, with injected gas coming both from field produced gas and imported gas; A blow down phase, including gas back-production from the initial injectors. In a previous paper, it was demonstrated that:Without specific upscaling techniques, the two production phases request a different definition of the net to gross, leading to difficulties to simulate the entire production period; The gas-oil ratio developments at the producers are highly sensitive to how the reservoir layering is derived from the heterogeneity captured at the wells. The relevance of that work was limited, due to a simplified fluid description (live oil / wet gas fluid model) that could not accurately simulate the various processes taking place during a gas cycling scheme. This paper presents new results, obtained with a compositional description of the fluids using an equation of state. The key results are:A comparison of various techniques to derive live oil / wet gas fluid models from the compositional one, and the implications in term of reservoir simulation results; The set up, validation and implementation of an upscaling technique based on a comprehensive review of the physical phenomenon taking place in the reservoirs; The fact that, using this technique, both production phases can be modeled consistently. Introduction Smørbukk field The Smørbukk field is located in the Norwegian Sea, within the Åsgard development. Smørbukk contains layers of sand bodies with good horizontal communication. The layers are thin compared to their horizontal extension, and vertically, there are large permeability contrasts. The field contains gas condensate with an oil rim, and is currently produced by gas injection in the gas cap, and down dip oil production. Initial temperature is up to 165°C and initial pressure is up to 50 MPa. Production started in May 1999. Phase two of the field development consists of a blow down phase. Lower Tilje formation Lower Tilje formation constitutes two of the deepest reservoirs of the Smørbukk field, and is characterized by relatively high permeabilities compared to other geological formations. As most of the gas injectors and the producers are near vertical and perforated into most of the Smørbukk reservoirs, lean gas front simulated from full field reservoir models develop faster in this formation, leading to a rapid increase of gas oil ratios in the producers located near the major injection points. As it is crucial for this off shore development to produce with a minimum gas oil ratio, this formation has been studied with greater attention. Heterogeneity and upscaling Large permeability variations are observed and modeled within Lower Tilje formation. Core and log derived permeability data show up to 6 orders of magnitude variations within Lower Tilje formation, and minipermeameter data show even higher variations, especially located into few, very thin, and very permeable streaks. This condition leads to a difficulty when defining the net to gross parameter:Either a permeability cutoff is introduced, keeping the high permeable sands where the injected gas will flow the easiest, and in this way enable proper reproduction of the gas injection period; Or no permeability cutoff is introduced, and this way all the pore volume that will be solicitated during the blow down period is incorporated. In reference 4, an upscaling strategy was proposed to honour properly the fluid behaviour during the two production periods. This method was introduced to upscale the flows for a simplified fluid model.
- Europe > Norway > Norwegian Sea > Tilje Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 479 > Block 6506/12 > Åsgard Field > Smørbukk Field > Åre Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 479 > Block 6506/12 > Åsgard Field > Smørbukk Field > Tofte Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (2 more...)