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The decision analysis process to develop a petroleum field can be very complex. This process contemplates a set of tasks, which include the study of various representative scenarios, and different production strategies that aid decision-making. However, when it comes to giant reservoirs, the computational requirements of the respective simulation models may be too high. High computational cost may demand simplification that may yield suboptimal solutions so it is desirable to find simplifications that preserve the quality of the solutions. One approach to reduce the simulation requirements is to divide the reservoir into sectors, and to use sector models isolated in the decision making process. This study evaluates the feasibility of using a model of an isolated sector from a giant reservoir in the management of this sector. The observed decrease in the simulation time of the isolated model makes this methodology attractive. However, it is necessary to evaluate in advance the impacts of its use on the flow behavior of this sector when inserted in the Full Field model. The case study presented is a deterministic realization of a reservoir with analogous characteristics to the Mero pre-salt field, with high communication along the reservoir. The global differences found between the isolated model and the Full Field model presented a range that justifies the use of the isolated model in the development process of this sector, without losing significant accuracy in the results. A methodology is proposed to evaluate the differences between both models using field and well indicators. Discussions about the impact of local differences between the two models are presented. The causes of these differences were investigated and attributed to three main factors: the production strategy; changing of boundary conditions; and rock properties of the model.
The significant quantities of oil contained in fractured karst reservoirs in Brazilian pre-salt fields adds new challenges to the development of upscaling procedures to reduce time on numerical simulations. This work aims to represent multiscale heterogeneities in reservoir simulators based on special connections between matrix, karst, and fracture mediums, both modeled in different grid domains within a single porosity flow model. The objective of this representation is a good balance between accuracy and simulation time. The principle combines the Embedded Discrete Karst Model (EDKM) and the Special Connection Fracture Model (SCFM), both developed by
The significant oil reserves related to karst reservoirs in Brazilian pre-salt field adds new frontiers to the development of upscaling procedures to reduce time on numerical simulations. This work aims to represent karst reservoirs in reservoir simulators based on special connections between matrix and karst mediums, both modeled in different grid domains of a single porosity flow model. This representation intends to provide a good relationship between accuracy and simulation time.
The concept follows the Embedded Discrete Fracture Model (EDFM) developed by Moinfar, 2013; however, this work extends the approach for karst reservoirs (Embedded Discrete Karst Model - EDKM) by adding a representative volume through grid blocks to represent karst geometries and porosity. For the extension of EDFM approach in a karst reservoir, we adapt the methodology to four stages: (a) construction of a single porosity model with two grid domains, (b) geomodeling of karst and matrix properties for the corresponding grid domain, (c) application of special connections through the conventional reservoir simulator to represent the transmissibility between matrix and karst medium, (d) calculation of transmissibility between karst and matrix medium.
For a proper validation, we applied the EDKM methodology in a carbonate reservoir with mega-karst structures, which consists of non-well-connected enlarged conduits and above 300 mm of aperture. The reference model was a refined grid with karst features explicitly combined with matrix facies, including coquinas interbedded with mudstones and shales. The grid block of the reference model measures approximately 10 × 10 × 1 meters. For the simulation model, the matrix grid domain has a grid block size of approximately 100 × 100 × 5 meters. The karst grid domain had the same block size as the refined grid. Flow in the individual karst grid domain or matrix grid domain is governed by Darcy's equation, implicitly solved by simulator. However, the transmissibility for the special connections between karst and matrix blocks is calculated as a function of open area to flow, matrix permeability and block center distance. The matrix properties were upscaled through conventional analytical methods. The results show that EDKM had a considerable performance regarding a dynamic matching response with reference model, within a reduced simulation time while maintaining a higher dynamic resolution in the karst grid domain without using an unconstructed grid.
This work aims to contribute to the extension of EDFM approach for karst reservoirs, which can be applied to commercial finite-difference reservoir simulators and it presents itself as a solution to reduce simulation time without disregarding the explicit representation of karst features in structured grids.
Post-salt carbonate fields are produced by depletion for more than thirty years in Campos basin, Brazil. Usually, they have recovery factors lower than 10%. This article presents a naturally fracture reservoir (NFR) simulation study with undersaturated pressure with no active gas cap and a small aquifer. This work includes a reservoir decision analysis which was done using uncertainty analysis, assisted optimization, comparison among strategies and a reliability test to check how production strategy results behaves when uncertainty parameters are used.
The goal is to present a secondary recovery method to improve oil recovery for this field using the best strategy among water, gas, water and gas and immiscible water-alternating gas (IWAG) injection. Although those methods are highly used for carbonates among oil industries worldwide they are not commonly used in carbonates fields located offshore Brazil, especially in carbonates with oil or mixed wettability. Selection of the best production strategy for this reservoir was determined through a full-field simulation using a commercial simulator with double porosity model.
The main application of this work is the possible implementation of a new production strategy that can change paradigm at how carbonates are produced offshore Brazil. The results and conclusion are based on alternatives to maximize oil production and net present value (NPV).
Comparison among the production strategies indicated water injection as the best way to produce this type of reservoir. The results showed that this method is robust because its economic results did not alter when different parameters representing the major uncertainties were used.
Further studies and implementation of water injection as secondary recovery strategy can boost production at new and mature fields for the huge carbonate play located at the post-salt part of Campos Basin. Indeed, any successful production strategies for carbonates have potential to be extended to pre-salt fields.
Reservoir heterogeneities increase practical and theoretical problems for understanding fluid flow among rocks that contain them. NFR is highly heterogeneous and its characterization, production mechanisms, modeling and simulation are completely different from conventional reservoir. Reservoir production mechanisms in naturally fractured reservoirs are more complex than single porosity reservoirs because, in addition to matrix properties, fracture system properties and factors controlling fluid exchange between the matrix and fractures should be analyzed. Oil recovery factors at this type of reservoir vary greatly because its production depends on matrix flow, fracture system connectivity, matrix-fracture iteration, wettability and how those factors affect the main production mechanism.
Early identification of a fractured reservoir is very important to avoid field jeopardy; indeed if the correct treatment and production strategy are applied since the beginning of the field plan, the results will be reliable production curves, good reservoir management and higher recovery efficiency.
Depletion in a fractured reservoir generates fluid expansion; fluids are then transferred from matrix to fractures. Simultaneously capillarity, gravity, heterogeneity and capillarity continuity can increase or decrease fluid recovery from matrix system. If injection is performed, fluid injected can easily surpass matrix and reach fractures leaving a lot of bypassed oil what usually results in inefficient displacement.. This is the main reason why the use of secondary recovery for NFR and carbonates is limited in Brazilian's post-salt carbonate fields.
Pressure maintenance is important for reservoir management and this is valid for any type of reservoir, even NFR where higher pressure increases imbibition in spite of rock wettability.