Compressional ∆T 240 10 0 10
Caliper in.
Gamma Ray gAPI
Bit Size in.
20 Deep Resistivity 100 20
Depth ft
0.5 0.5
Shallow Resistivity ohm.m
ohm.m 10 10 2.2
Density Crossover µs/ft
g/cm3 40
Depth, 823 ft
2.7
30 %0 Neutron
T1 time Depth, 832 ft Tony—Figure 10/11_1 800 T1 time Depth, 847 ft
However, many reservoirs contain more than one fluid type: Fluid composition may vary continuously or discontinuously across a reservoir interval. Fluid gradation is not always apparent with conventional well logs, and surprises can occur in both the early and later stages of production.
A North Sea exploration well was drilled to evaluate a reservoir that, based on an offset well, was believed to contain gas condensate.17 Adjacent gas-handling infrastructure made the prospect an inviting target. Resistivity and density-neutron logs clearly indicated that this exploration well had a significant hydrocarbon deposit with approximately 48 feet [15 m] of net gas pay.
T1 time Depth, 874 ft 850 T1 time Depth, 886 ft 900 T1 time
> Determining fluid type. The resistivity and porosity data indicate a hydrocarbon interval from 822 to 872 ft. Mud logging during drilling suggested gas or condensate throughout the interval. D-T1 maps from data acquired from the MR Scanner tool provide a different fluid analysis. The lowest interval (bottom right) contains connate water (white circle) and oil-base mud filtrate (OBMF). Successively higher points indicate a transition from light oil to gas (black circles). Based on interpretation of the NMR D-T1 maps, this reservoir contains oil below 840 ft, rather than the expected condensate and gas.
signal is the mud filtrate and that it has displaced heavy oil in the reservoir, although the heavy oil is invisible to the MR Scanner tool. If the filtrate were displacing movable formation water, the water signal would be constant at deeper DOIs.
In a lower interval, the resistivity is high, exceeding 100 ohm.m, which leads interpreters to conclude that filtrate displaced oil. However, for the upper zones with lower resistivity values, the answer is less obvious. Lower resistivity values would suggest the presence of water rather than oil. NMR data provide the missing fluid information. Hydrocarbon in the form of heavy oil was displaced by the filtrate. Because the water signal from the filtrate is present in the 1.5-in. Shell No. 1 measurement but disappears
in the 4.0-in. Shell No. 8 measurement, these zones should produce water-free oil. A strong water signal remains in the D-T1 maps at each DOI, but its source is irreducible bound water.16 Based on the answers provided by the 4D processing, the operator can confidently produce from the upper and lower sections with an expectation of little or no water production. Minimizing water production decreases upfront costs for surface equipment and, because water removal and disposal are not required, reduces costs over the life of the well.
Fluid Characterization
Fluid type directly affects the economic value of a field, and surface facility decisions depend on an accurate understanding of reservoir fluids.
MR Scanner data were then acquired in a saturation-profiling mode. Diffusion and T1 distri - butions, extracted from multiple wait time, variable echo-spacing sequences, were derived from the data. T2 distributions were computed, but T1 distributions proved better for analyzing the long relaxation times of the fluids in this reservoir. Water and hydrocarbon saturations at 1.5-, 2.7- and 4.0-in. DOIs were computed from the data acquired in two separate logging passes. The D-T1 maps at sequential depths were plotted and, although there is a clear gas signal in the upper part of the reservoir, the NMR interpre - tation concluded that a significant portion of the reservoir contained light oil—not condensate as originally anticipated (left). Closer analysis of the data and the D-T1 maps identified the gas/oil contact in the reservoir, as well as a stratigraphic feature assumed to be a vertical-permeability barrier. A 4D inversion enhanced the deeper shell measurement. The 1.5-in. shell data indicate a significant volume of oil-base mud filtrate (OBMF), but the deep shell output is less affected by the OBMF (next page). The porosity and permeability derived from the MR Scanner data were immediately available to the client in the field. The acquired data were sent to a Schlumberger computing center for advanced processing. NMR fluid-property data were returned in time to assist in picking depths for pressure and sample points. Pressure plots indicated three different fluid gradients. Fluid samples confirmed the presence of gas in the upper interval and oil in the lower interval. Unfortunately, filtrate contamination prevented an accurate PVT analysis.
A two-stage drillstem test (DST), conducted after the well was completed, confirmed the presence of oil in the lower interval. The NMR data provided improved understanding of the complex nature of the reservoir fluids. The
18
Oilfield Review
Diffusion
Diffusion
Diffusion
Diffusion
Diffusion
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