Abstract
Understanding the flow behaviour of fractured wells is crucial to operators and service companies in evaluating the effectiveness of stimulation work performed on the well. New insights in modelling of well transient pressure tests in hydraulic fractured unconsolidated sand is presented in this paper by utilizing 3-D numerical black oil simulation in single and two layered sand reservoirs with a thin shale layer in between. The upper layer perforated and fractured to treat the sand production as frack-pack technique and the well test has been conducted only on the upper layer. Porosity and permeability heterogeneities are classically evaluated from petrophysic well log measurements and through geological description of the reservoir, then possibly refined by simulation and history matching. The pressure measured in the well test in four cycles of drawdown and build up. The well bottom hole pressure (BHP) behaviour cannot be adequately described with conventional well tests analysis for the upper sand without including the flow from the lower sand.
Different scenario of production from upper with adding hydraulic fractured examined to match the oil/gas production and bottom hole pressure. A range of factors are examined that may impact the introduced fracture flow behaviour based on actual fractured well flow. The main fracture and reservoir parameters investigated include absolute permeability of upper layer, gas oil contact (GOC), relative permeability endpoints to oil and gas, hydraulic fracture properties (permeability, width) and extension and finally the skin factor.
The results of dynamic simulation model show that the model is very sensitive to the amount of gas production and hydraulic fracture vertical extension. We highlight through this example and sensitivity simulations that the GOC should be very close to the well preformation or else the pressure could not be matched. Hydraulic fracture vertical extension is required for matching of BHP and gas rate, without it, the gas rate will be very high in all of the simulation cases. The fracture connecting the upper layer to lower layer with only upper layer perforated. Absolute permeability from log cannot represent to the real permeably measured from well test. To match all historical data absolute permeability, need to be reduce by one order of magnitude. Finally, the model is sensitive to the skin factor for matching of pressure build up.
The main business questions were answered through integrated analysis of the analytical well model and dynamic simulation of single model to identify the source of excess gas and understand the well performance to reduce the uncertainty in production forecast. Fast approach in the single well modeling and efficient approach in the integration in the workflow is described in detail in the paper.
