In carbonate reservoirs, it has been commonly reported that natural fracture is the primary factor that governing hydrocarbon production. By a renewed investigation into the Niobrara low permeability carbonate at the Wattenberg field in the Denver-Julesburg basin (DJ), the authors have observed a series of petrophysical factors that can be reflected by well logs affect well performance. The conventional well logs have been used to calculated or estimated these petrophysical parameters, which include irreducible water saturation calculated by the resistivity and porosity; solution gas oil ratio computed from the neutron and density; pore structure connectivity reflected by the spontaneous potential; the proximity to faults inferred from the density correction log; and original high reservoir pressure determined from changes in resistivity and neutron of overlying shale.
The Niobrara formation at the Wattenberg field in the DJ basin is a sequence of marine shale, marl, and thin carbonate deposits. Three layers of carbonate with a combined thickness of 45–100 feet are separated by shale intervals. Except the absence of the upper layer carbonate in certain portion of the field, the Niobrara is continuous throughout the entire Wattenberg. The permeability measured at the most permeable part of the formation is limited to micro-Darcy level. Because of the low reservoir qualities restricted by the low permeability, this carbonate horizon had been largely ignored for the past decade.
In the wake of the recent oil boom started in the late 2004, the enthusiasm toward the Niobrara resurfaced at the Wattenberg field. A pilot project involving a dozen wells was conducted to test the potential of the Niobrara. The overall well performance is very discouraging. At that point, a legitimate question was asked: what are the factors that govern the hydrocarbon production from this low quality carbonate horizon?
When it comes to carbonate, natural fracture is usually considered the primay factor that affect the well performance. It is commonly accepted that the FMI logs and whole core samples are the crucial means to evaluate the natural fractures. Because of the sparse of the FMI log and whole core samples available for this giant field, we found them less helpful to determine the areas where the Niobrara possesses higher reservoir qualities. Instead, we turned to the wealthy conventional well logs collected from several thousand wells for solutions. Through intensive investigation into well log responses against the Niobrara, the authors have identified the well log parameters that reflect the key reservoir qualities, delineated high quality Niobrara areas, realized encouraging oil and gas production, and made the Niobrara a primary objective at the Wattenberg field.
The porosity of the Niobrara varies from 12% to 16% throughout the Wattenberg field. However, the well performances cannot be correlated with the hydrocarbon volumetric calculated by the porosity measurement. While the hydrocarbon volumetric change is more gradual, the well performance changes are very abrupt. Decent producers and non-producible wells can exist in the areas where the porosity change is not significant. On the other hand, the authors have observed that the dramatic change in well performance mimic the irreducible water variation calculated by the Archie Law using the porosity and resistivity logs.
Since the Niobrara carbonate contains high percentage acid-dissolvable composition and low shale content, the basic Archie formula below can be directly used to calculate the water saturation.