The effect of fracturing on permeability in carbonate reservoir rocks

Abstract

Hydrocarbon flow rates from tight carbonate reservoirs often depend on the distribution and properties of fractures throughout the reservoir interval. Hence, quantification of fracture parameters can contribute to understanding of reservoir characteristics and reservoir potential. In this paper, natural fractures in tight carbonate reservoir rocks of the Upper Cretaceous Shiranish Formation in the Taq Taq field (Kurdistan Region of North Iraq) were examined primarily using core samples, XRMI micro-resistivity image logs and conventional wireline logs, with additional dynamic data from well tests and mud logs. The Shiranish Formation is composed of a variety of limestones and argillaceous limestones with arithmetic mean matrix porosity and geometric mean permeability values of 1.64 ± 0.37% and 0.0223 ± 0.59 mD, respectively. However, fracturing has enhanced the permeability by up to four orders of magnitude above the maximum matrix permeability (1.79 ± 0.59 mD). Hydrocarbons are produced entirely from the fracture network in these rock types in the Taq Taq reservoir. Observed open and partially-open fractures have NE-SW orientations; these are classified as macro-fractures with average aperture of 0.17 ± 0.18 mm, arithmetic mean height of 11.70 ± 45.40 mm and arithmetic mean length of 26.7 ± 32.32 cm, where the uncertainties are standard deviations. Fracture aperture size and fracture height control fracture permeability and fluid flow. However, while fracture frequency has no effect on permeability, fracture distance distribution influences flow rates and hydrocarbon production. The dominant NE-SW trending fractures are more likely to remain open within the NE-SW oriented present day stress field at Taq Taq. Furthermore, the effect of overburden stress on the permeability and production rate was examined in laboratory tests on core plugs by increasing the confining stress during permeability measurements using constant flow rates. It was found that the magnitude of fracture permeability was reduced by 70% by applying 4000 psi of confining stress. In the reservoir, this effect would be exacerbated by reduced reservoir fluid pressures as a function of production. However, fractures with apertures greater than 0.10 mm are preserved as productive fractures even at high confining pressures and implying that hydraulic fracturing could open existing fractures significantly, enhancing production. This last observation implies that the use of hydraulic fracturing in tight carbonate reservoirs with natural fracturing is likely to be commercially viable.