Density Correction –0.2 g/cm3 0.2
Deep Resistivity 0.1 ohm.m 1,000
0
Gamma Ray gAPI
200
Shallow Resistivity 0.1 ohm.m 1,000
Depth ft
45 1.95
Neutron Porosity %
Formation Density g/cm3
0 2.95
50 50 50
Shell No. 1 Bound Fluid %
Oil %
Free Water %
0 0 0
50 50 50
Shell No. 4 Bound Fluid %
Oil %
Free Water %
0 0 0
X,100
X,200
OWC
X,300
X,400
X,500
> OWC not found. Early logging attempts with the MR Scanner tool produced inconclusive results. In the well shown, the fluid saturations were computed using data from Shell No. 1 (Track 4) and Shell No. 4 (Track 5). Oil (green) is indicated from top to bottom of the interval, but it is OBMF, not native oil. Free water (blue) is also seen throughout the interval in data from both shells. A DST located the OWC at X,204 ft. From the NMR data, its location is not obvious. The presence of free water above the OWC was attributed to noise in the data and influenced the decision to take stationary measurements for future wells.
production. The company reactivated the field and then drilled evaluation wells to properly characterize the reservoir and determine locations for horizontal multilateral producing wells. In the first well logged with the MR Scanner tool, the tool was part of a logging suite that consisted of resistivity, density porosity, neutron porosity, acoustic and spectroscopy tools along with a formation pressure and sampling program.
In the past, conventional logging tools had been unable to identify the OWC. Fluid gradients from pressure data were not conclusive. NMR saturations were acquired using data from the
MR Scanner tool. However, the saturations indicated that the entire zone was pay, which was known to be incorrect based on production from offset wells.
The inability of the NMR tool to identify the OWC was attributed to less-than-optimal acquisi - tion parameters for the challenging case of this HRLC pay. The reservoir contains low-viscosity light oil, and NMR experts concluded that the lack of success in locating the OWC resulted from using a wait time that was insufficient to fully polarize the native oil. A new acquisition sequence was created to address the underpolarization. In the next well, the MR Scanner tool used this modified sequence, acquiring data from the
20
1.5-in. and 2.7-in. shells (above). The results again indicated pay throughout the interval. OBM filtrate had flushed out native water and oil throughout the interval. Upon closer inspection of the results, a subtle increase in the computed water volume was observed in the water leg from the 2.7-in. shell data compared with that computed from the 1.5-in. shell.
The presence of OBM filtrate explained the oil in the water leg. The 2 to 3% of free water seen in the known oil leg was not so easily explained. It was assumed that the signal-to-noise ratio was insufficient for accurate volumetric calculations and the increase in the computed water volume was due to noise.
Oilfield Review
Bad Hole Flag
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