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This paper presents an overview of the SACROC Unit’s activity focusing on different carbon dioxide (CO2) injection and water-alternating-gas (WAG) projects that have made the SACROC unit one of the most successful CO2 injection projects in the world. Several studies explored the possibility of improving both areal and vertical sweep efficiency in mature water-alternating-gas (WAG) patterns in the Magnus oil field.
The projects are designed to reduce technical risks in enhanced oil recovery and expand application of EOR methods in conventional and unconventional reservoirs. This paper presents an overview of the SACROC Unit’s activity focusing on different carbon dioxide (CO2) injection and water-alternating-gas (WAG) projects that have made the SACROC unit one of the most successful CO2 injection projects in the world. A new type of organically modified silica glass that can remove a wide variety of oils and contaminants from produced and flowback water is showing promising results as it undergoes field trials.
Aqueous foam has been demonstrated to have promise in conformance-control applications. This paper explores the foaming behavior of a CO2-soluble, cationic, amine-based surfactant. In the complete paper, a new assessment of the WAG-hysteresis model, which was developed originally for water-wet conditions, was carried out by automatic history matching of two coreflood experiments in water-wet and mixed-wet conditions. This paper presents an overview of the SACROC Unit’s activity focusing on different carbon dioxide (CO2) injection and water-alternating-gas (WAG) projects that have made the SACROC unit one of the most successful CO2 injection projects in the world. Accurate determination of relative permeability hysteresis is needed to predict water-alternating-gas (WAG) injection reliably.
Hamedi Shokrlu, Yousef (Computer Modelling Group Ltd.) | Pathak, Varun (Computer Modelling Group Ltd.) | Kumar, Anjani (Computer Modelling Group Ltd.) | Salazar, Victor (Computer Modelling Group Ltd.)
Applicability of Enhanced Oil Recovery (EOR) processes is gaining interest among offshore operators in recent years. CO2/miscible gas injection and Water Alternating Gas injection (WAG) are the most attractive EOR methods being considered by most offshore operators. Due to limitations imposed by the surface facility, any process optimization done through standalone reservoir simulation could be unreliable as the facility constraints and its effects are neglected. In order to minimize risk and reduce uncertainty, successful modelling and optimization of such projects requires integration of subsurface modelling with surface facility model.
In this work, field development and optimization of a complex offshore production system, from a Pre-Salt carbonate reservoir offshore of Brazil is studied. Different field development scenarios, including water flooding, miscible gas injection, and WAG injection, are considered. Compositional fluid model is used in order to correctly model the fluid mixing effects and miscibility. Pressure change and thermal effects are considered in all the facility equipment. The complexities of the surface network, including gas sweetening, compression, and fluid blending are included in the integrated model.
A new multi-user, multi-disciplinary Integrated Production System Modelling (IPSM) tool is used to fully-implicitly couple reservoir simulation with surface facility model. Production from the offshore asset is optimized for different development scenarios. The provided IPSM approach optimized operational schemes that were consistent with the constraints of the offshore facility. Additionally, with this new approach, all users from different disciplines were able to collaborate seamlessly, and any possible inconsistencies and discontinuities that could occur due to use of multiple decision making tools were removed.
The use of integrated production systems modelling for optimizing EOR schemes in offshore assets, particularly miscible WAG, is proved to provide more robust answers. The complexities and Uncertainties of such processes, for both reservoir and facility models, are successfully studied.
A suite of production logs can provide important information for fine-tuning tertiary recovery operations. Below the casing, oil is produced in the open hole under WAG (water-alternating-gas) recovery. The well produces 1381 RB/D of water, 119 RB/D of oil, and 245 RB/D of CO2. Carbon dioxide, CO2, dissolves primarily in the oil and secondarily in the water. The produced oil, with CO2 in solution, bubbles (or "percolates") up through the flowing water.
The Prudhoe Bay field, located on the North Slope of Alaska, is the largest oil and gas field in North America. The main Permo-Triassic reservoir is a thick deltaic high-quality sandstone deposit about 500 ft thick with porosities of 15 to 30% BV and permeabilities ranging from 50 to 3,000 md. The field contains 20 109 bbl of oil overlain by a 35 Tcf gas cap. The oil averages 27.6 API gravity and has an original solution gas-oil ratio (GOR) of about 735 scf/STB. Under much of the oil column area, there is a 20- to 60-ft-thick tar mat located above the oil-water contact (OWC).
Prediction of a miscible flood is best done with a compositional reservoir simulator. The simulation must be able to predict the phase behavior as well as the sweep behavior in the reservoir to forecast such quantities as incremental oil recovery, miscible-solvent requirement, and solvent utilization efficiency and to optimize such variables as solvent composition, operating pressure, slug size, water-alternating-gas (WAG) ratio, injection-well placement, and injection rate. The compositional reservoir simulator calculates the flow in up to three dimensions of solvent, oil, and water phases as well as n components in the solvent and oil phases. It also computes the phase equilibrium of the oil and solvent phases (i.e., the equilibrium compositions and relative volumes of the solvent and oil phases) in each gridblock of the simulator. In addition, it computes solvent- and oil-phase densities.
The objective of scaleup is to take the behavior predicted from detailed, fine-grid reference models that at best represent only a few wells and a tiny part of the reservoir and transfer it to a model that attempts to represent many wells and the integrated behavior of the entire compositionally enhanced solvent flood (or at least a significant portion of it). Jerauld is a good example of the application of this method. Several reference models describe different areas of the field. Water/oil, solvent/oil, and solvent/water pseudorelative permeability relations are developed, along with pseudotrapped-solvent and solvent-flood residual oil values, so that the relevant behavior of the reference models is reproduced by corresponding models that have the same coarse grids as the full-field model. The coarse-grid models, of course, represent the same parts of the full-field model that the reference models represent.