Stochastic 2D Well-Path Assessments for Naturally Fractured Carbonate Reservoirs

Abstract

Summary Simple but geologically reasonable and calibrated 2D stochastic models are useful to quantify significant risks and uncertainties associated with alternative-development-well trajectories, particularly when statistical relationships can be established to help quantify those risks and uncertainties, and when the geologic features that create the risks and uncertainties are not adequately addressed within reservoir-flow models. Our example stochastic 2D model considered the naturally fractured depositional-slope region of an isolated carbonate buildup, and the model was populated with relevant features including distributions and geometric details of natural fractures, natural-fracture clustering, and intraformational slope clinoforms that define a mechanically layered sequence. The model was calibrated by use of well-production results and production-logging data so that it reproduced observed well results for cases where the lower sequence boundary does not occur above the oil/water contact (OWC), adding confidence that the model could be used to represent the statistical effect of various alternative trajectories for future wells. Experimental design (ED) was used to determine the significant uncertainties and well-path decisions. Heel and toe elevation and the number of clinoforms encountered by the well were the only significant variables for modeling the frequency of water production. For modeling the frequency of direct well communication to the gas cap, the same variables were significant, in addition to well direction, completion length, and fracture density. The amount of fracture clustering applied in the model was also significant. For our example case, changing the well-elevation profile was effective in managing gas or water risks; however, tradeoffs were evident—and quantified—in attempting to simultaneously address both risks. Minimizing drawdown was not an effective strategy because productivity was low and rarely resulted in economic water-free production if any open fracture connected the well with the aquifer.

The Role of Chemistry in Fracture Pattern Development and Opportunities to Advance Interpretations of Geological Materials

“…Consequently, other evidence is commonly combined with direct observations to diagnose fracture attributes. The presence of fractures is commonly inferred from anomalous fluid flow patterns evident in well tests (e.g., Da Prat, ; Narr et al, ; Solano et al, ; Wehunt et al, ). Thus, there are intervals in the deep boreholes that are transmissive, and there are also large intervals that have low permeability, often in close proximity.…”