EAGE Workshop on Naturally Fractured Reservoirs in Asia Pacific

We attempt to model the contributed-natural fractures to hydrothermal flow by using the geological fracture drivers and geomechanics recommendation in the naturally-fractured reservoir (NFR) modelling through the discrete fracture network (DFN) method. We also compare models that use different parameters input to figure the most realistic permeable NFR model and fit the actual reservoir condition in the well-scale.

As the result, the DFN model derived from CSF, deterministic fault and MEQ gives the fittest permeability model with the actual flow condition in the well-scale. The reason is that the permeability control in the reservoir is mostly associated with fracture intensity. In other words, high fracture with a certain orientation and intensity penetrated by the well will give high permeability magnitude, thus characterizing the NFR through the DFN model will be a benefit. This permeable zone model can be further used in the next well geothermal well targeting. The DFN from purely tectonic fracture driver gives less match permeable model, that might be influenced by the level of confidence of the existence or geometry of deterministic fault and also the stress magnitude and orientation, whereas in this case we still need more data to have more prominent principle stress magnitude.

In this abstract, a novel methodology was outlined by utilising Net Pore Volume (NPV) approach to estimate potential rock space filled by hydrocarbon in naturally fractured basement reservoirs for volumetric calculation by showcasing a dataset within the Asia Pacific region. The Depth-Area-Thickness (DAT) as proposed by James et al. (2013) are commonly applied for gross rock volume (GRV) estimation as part of the hydrocarbon volumetric assessment input in geological reservoirs, which considers the trap geometry and configuration as well as the hydrocarbon contact definition. This method is not suited to capture the identified fractured basement zone or network, which the hydrocarbons are stored that ultimately determines its volumetric size. Nonetheless, Robert Trice (2018) in specific case to fractured basement play have summarised several variables in the reservoir characterisation as basis for volumetric assessment in the Lancaster field (i.e. fracture planes area, zone width, aperture and fracture density). Herein, the proposed method in this paper focuses on the integration of seismic derived fractured planes as a framework for net pore rock volume estimation coupled with uncertainties analysis as part of input into the stochastic volumetric assessment.

The Pondok Mulia structure is located in Tambun Field, Pertamina EP Zona 7-Area 1, West Java. The main reservoir of this structure is the Pre-Cibulakan carbonate which usually develops locally as a patchy limestone unit, grows over the underlying igneous rocks. The reservoir mapping of this carbonate rock unit is problematic, with one of the major challenges is to map fracture intensity distribution within the reservoir to optimize oil production.

This carbonate is exposed and experienced dissolution and karstification processes, resulting in cavities in fracture zones, which is also indicated by the presence of dual-porosity from the core data. The seismic interpretation shows that this unit formed a closure as a part of the Pondok Mulia dan Pondok Makmur structures.

This study utilizes the Full-bore Formation Micro Image (FMI) data in log intensity and Secondary Porosity Index (SPI) obtained from sonic porosity and neutron porosity. The acoustic impedance, coherence, and ant-tracking seismic attributes assist the interpretation. In this preliminary study, we combined both seismic and log data using discrete fracture networks to map the distribution of fractures. At this point, we combined seismic attributes and well log derived attributes to define the fracture connectivity and intensity.

The formation evaluation of the tight sand reservoirs is challenging at different points of view. Several factors affect the recording and make the evaluation and the potential in place assessment harder. That’s why, the new technologies and customized workflows deployed in such reservoirs are greatly helping in narrowing the uncertainties encountered at different levels of the tight sand reservoirs lifecycle.

One of the milestone steps is the formation fluids identification and sampling. In the past, the selection method of the intervals for fluids sampling using the MDT tool was based on conventional logs by selecting intervals with higher porosity. However, this method has shown its limitations in tight reservoirs due to the low porosity and permeability.

No Summary.

The study area is a shallow water field located in Cuulong Basin, offshore Southern Vietnam, 120 km east –southeast of Vung Tau city. Reservoir rocks consist of fractured sandstones (primary target) aged Oligocene/Eocene overlapping granite basement (secondary target). Five wells discovered oil in the sandstone reservoirs while no oil water contact has been encountered. Naturally Fractured sandstone reservoir has low average matrix porosity < 10% and dual permeability system with average matrix permeability of < 1mD evident from drill stem tests (DST), routine core analysis, image logs and drilling experiences such as mud losses during drilling. Reservoir fluid is light oil with low viscosity and drive mechanism is fluid flow through network of natural fractures. This study was conducted to characterise natural fractures permeability under current state of in-situ stresses to ultimately determine the best well orientation in order to intersect the greatest number of critically-stressed fractures for the optimum productivity from future wells. Analytical modelling considered the in-situ conditions to calculate the downhole pressure required to initiate shear slip on well-oriented fractures to become critically stressed and hence permeable to drilling fluid.