Abstract:A practical method to adapt fractures both micro and macro as flow enhancing properties in a single porosity model is introduced to simulate Ujung Pangkah fractured carbonate reservoir. This approach is taken because dual porosity modeling attempt fails to explain the behavior of many wells which experience early water breakthrough and/or excessive water production in Ujung Pangkah field.
The enhancement factor term is used to define the degree of permeability enhancement by diffuse or micro fra… Show more
When a rock is fractured, its capillary pressure may radically change. In other words, the effective capillary pressure of the fractured rock is no longer the same as that of its original matrix. This is an important phenomenon to consider when building static and dynamic models of fractured reservoirs. Fracture capillary pressure can have a significant impact on modeling of initial water saturation. In a reservoir model, initial water saturation is typically calculated as a function of capillary pressure. While matrix capillary pressure can be obtained by measurements of core plugs, fracture capillary pressure is hardly known from actual data due to limited or no measurements from fractured cores. In this case, a practical solution to assign capillary pressure in a model is to modify the matrix capillary pressure in a reasonable manner. Generally, matrix of a tight (low porosity) rock can have very high capillary pressure, but once it is fractured, the water saturation in the fractured rock should be dramatically decreased. If we ignore this phenomenon, water saturation will be significantly over-estimated and consequently oil-in-place is under-estimated. Another impact of the incorrect capillary pressure can be on dynamic models, in which the model will show significantly early water breakthrough and dramatically higher water cut than field data. Therefore, correctly modeling fracture capillary pressure is critical for both static model building and dynamic model simulation. The proposed solution is to assign the effective capillary pressure for fractured rocks independently from non-fractured ones. The solution has been applied in a couple of giant carbonate offshore reservoirs in the United Arab Emirates and has demonstrated significant benefits in reservoir models with improved fluid stability and better water cut matches.
When a rock is fractured, its capillary pressure may radically change. In other words, the effective capillary pressure of the fractured rock is no longer the same as that of its original matrix. This is an important phenomenon to consider when building static and dynamic models of fractured reservoirs. Fracture capillary pressure can have a significant impact on modeling of initial water saturation. In a reservoir model, initial water saturation is typically calculated as a function of capillary pressure. While matrix capillary pressure can be obtained by measurements of core plugs, fracture capillary pressure is hardly known from actual data due to limited or no measurements from fractured cores. In this case, a practical solution to assign capillary pressure in a model is to modify the matrix capillary pressure in a reasonable manner. Generally, matrix of a tight (low porosity) rock can have very high capillary pressure, but once it is fractured, the water saturation in the fractured rock should be dramatically decreased. If we ignore this phenomenon, water saturation will be significantly over-estimated and consequently oil-in-place is under-estimated. Another impact of the incorrect capillary pressure can be on dynamic models, in which the model will show significantly early water breakthrough and dramatically higher water cut than field data. Therefore, correctly modeling fracture capillary pressure is critical for both static model building and dynamic model simulation. The proposed solution is to assign the effective capillary pressure for fractured rocks independently from non-fractured ones. The solution has been applied in a couple of giant carbonate offshore reservoirs in the United Arab Emirates and has demonstrated significant benefits in reservoir models with improved fluid stability and better water cut matches.
Pangkah field located at offshore East Java Indonesia is an oil and gas producer within fractured carbonate reservoir lithology. Fractured corridors introduce challenges during drilling and production phase. To optimize production, several wells had been completed with novel Inflow Control Device (ICD) design. This paper highlights the potentials of such customized ICD's innovation with integral sliding sleeve.
This novel ICD design preserves intended ICD position, and in addition could be shifted in the downhole later either to be in open or closed position if required. Either coil tubing or electric-line could be deployed to shift the downhole 3-positions of this integral ICD with sliding sleeve. The integral design allows a fully open position for well stimulation or circulation in formation damage treatment. Meanwhile another position enables ICD configuration for inflow control. The last position which is fully-shut or closed can be activated during completions string Run in Hole (RIH) to allow floating toward Total Depth (TD), minimizing torque and drag, and maintaining wash-down capability without wash pipe. The whole closed or floating system while RIH makes it possible to set assemblies of open hole hydraulic set packers or any pressure activated devices. During late-life, selective compartment could be shut-off against excessive water production decisively whenever required.
Good sealing of the open hole packers against borehole is essential for the effectiveness of open hole compartmentalization and ICD production. The open hole hydraulic packers must be placed and set properly within its expanding range. Combination of petrophysical analysis, caliper log, image log, seismic coherency, and drilling loss data are used to define the compartments and packer placement.
This novel ICD's innovation with water shut-off capability in addition to the main ICD's inflow control is designed comprehensively with 3D single wellbore dynamic modeling. ICD's single well dynamic modeling were executed along three phases i.e. pre-drilled, real-time and post-job. Each phase respond to operation readiness and reservoir management. Intensive engagement with asset team and realistic modeling design range lead to positive production results.
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