Fracture Pressure Prediction Using Empirical Approach for Rumaila Oil Field: A Comparison Study

Success of drilling operations strongly depends on accurately estimating fracture pressure, which is important for designing drilling operations and preventing problems. Additionally, other phases of the oil industry, such as increasing production and injection operations, require information about fracture pressure, making it essential to determine it precisely. Numerous correlations are available to determine fracture pressure, which is a vital property of a well. Some of these correlations depend on rock and formation characteristics, while others are based on log data. The primary goal of this paper is to predict the fracture pressure of different formations within the depth interval of 400-3500 m in the Rumaila oil field (southern Iraq) using empirical fracture correlations. This comparative study is important for detecting the accuracy of various correlations, which are crucial in optimizing oil field production and minimizing risks. Fracture pressure estimation was implemented using diverse correlations within the Techlog software, relying on parameters such as true vertical depth, pore pressure, and vertical stress extracted from well log data. The calibration process involved incorporating fracture pressure data points and minimum horizontal stress values. The obtained results of the methods of Denies, Matthews, and Zamora exhibit calibrated factor variations across a diverse range of geological formations. The corrected Denies Beta factor displays variability when applied to different formations. Specifically, for carbonate lithology, the Beta values approximate 0.18, while within shale lithology, they decrease to 0.1. The Alpha correction factor presents distinct values for varying rock types. In the case of carbonate rock, the Alpha values converge around 1.5, whereas within shale lithology, the Alpha values span between 1.15 and 1.35. In the context of carbonate lithology, the Matthews corrected factor spans a range from 0.3 to 0.9, while in shale formations, it fluctuates between 0.7 and -2.2. Notably, the calibrated factors associated with the Zamora methods M and C6 remain unaffected by lithological variations. However, the coefficient values for C5 exhibit a range of 1.1 to 1.4 for carbonate rock and 1.15 to 2.5 for shale rock.