New Integrated 3D-Fracture Modeling and Flow Simulation Study: A Giant Saudi Arabian Carbonate Reservoir
- Hisham M. Al Qassab (Saudi Aramco) | Mohammad A Al Khalifa (Saudi Aramco) | Zaki Al-Ali (Saudi Aramco) | Mohammed Ameen (Saudi Aramco) | Robert Phillips (Saudi Aramco) | Lee Hartley (Serco Assurance)
- Document ID
- Society of Petroleum Engineers
- European Petroleum Conference, 29-31 October, Aberdeen, United Kingdom
- Publication Date
- Document Type
- Conference Paper
- 2002. Society of Petroleum Engineers
- 5.1.5 Geologic Modeling, 5.6.4 Drillstem/Well Testing, 5.1.2 Faults and Fracture Characterisation, 1.2.2 Geomechanics, 5.5.3 Scaling Methods, 4.3.4 Scale, 5.5.8 History Matching, 1.6 Drilling Operations, 5.8.7 Carbonate Reservoir, 5.8.6 Naturally Fractured Reservoir, 1.6.9 Coring, Fishing
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An innovative fracture modeling process has been successfully developed and utilized in a giant Saudi Arabian fracture carbonate reservoir. This modeling process constrains the discrete fractures to sets of geologic drivers describing the fracture relationships to reservoir matrix properties such as porosity, lithology and stylolites as well as to structural attributes including faults and curvature. The reservoir has very good matrix permeability, but it is enhanced significantly by faults, fractures and strataform.
The workflow starts with the construction of a stochastic discrete fracture network generated in a given simulation volume by providing the static distribution of all relevant fracture parameters from image and core logs and geologic drivers. The fracture distribution is then validated in wells with the fracture counts from image logs and cores. The fracture counts from the model were found to give a consistent magnitude with the observed fracture counts in core and image logs in more than 70% match.
The fracture network is then translated into fracture properties by incorporating geo-mechanical in-situ stress information including direction, magnitude, and vertical gradient to identify open fracture and to determine the effective fracture aperture. Due to high matrix permeability a representation of the matrix and strataform was incorporated with the fractures to produce a discrete feature model of the combined fracture/matrix system. This is essentially single medium model was used to calibrate against well-test data. Single flow simulation was then performed for the discrete feature model on each of the cells in the model. The calculated fracture properties include fracture permeability, fracture porosity, and the transfer function (sigma) measuring the interaction between the matrix and the fracture.
The dynamic behavior of the simulated fracture permeability compared well to the Kh from pressure buildup tests. Results were very encouraging, as it appeared that in general, the fracture distribution in the reservoir had been properly described. Moreover, calibration of the fracture parameters such as permeability to match the observed dynamic behavior proved to be an effective way to achieve history match of both pressure and water cut, as was seen from simulation models using both dual porosity dual permeability and single porosity single permeability modeling techniques.
Many large oil and gas reservoirs in the Middle East are fractured with varying degrees. This represents challenges in optimum reservoir development. Loss circulation while drilling and early water breakthroughs are a few among the most common problems encountered in these reservoirs. Yet, the development of a reliable fracture model is very difficult to achieve.
In the non-fractured (conventional) reservoirs, permeability is dependent on the composition of the matrix. Where as in the fractured reservoir this is not the case. For example, the presence of a fault may substantially increase the permeability in a localized area. The challenge in fracture modeling is to define factors that control fractures and use them to generate a 3-D fracture model.
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