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Fluid identification and characterization
One role of the petrophysicist is to characterize the fluids encountered in the reservoir. Detection of a change in fluid type in the rocks while drilling is usually straightforward with the use of gas and chromatographic measurements. The article on mud logging discusses these various methods. Gas shows and oil shows while drilling are time-honored indicators of zones that need further investigation through logs, testers, and cores. In the rare case of gas-bearing, high-permeability rock drilled with high overbalance, gas will be flushed from the rock ahead of the bit, will not be circulated to the surface in the mud, and will not produce a gas show.
Water-based drilling mud
Because hydrocarbons are not always part of a water-based-mud formulation, sophisticated analytical chemical techniques can be used on the oil and gas samples circulated to the surface and captured to determine the properties of hydrocarbons in a given zone penetrated by the drill bit. Occasionally, small amounts of hydrocarbons are added to water-based mud to reduce friction on the drillpipe. This hydrocarbon response must be accounted for in any analysis. Sidewall samples will contain some remaining hydrocarbons when brought to the surface. If promptly wrapped, frozen, and analyzed, the crude remaining in the core can be used to characterize:
- Gas/oil ratio
- Other fluid properties
Companion sidewall samples can be analyzed at the wellsite for odor, color, fluorescence, and cut-fluorescence, which can be used to distinguish oil/water and gas/oil contacts. If one is uncomfortable predicting reservoir fluid properties from such a small sample, the zone in question can be sampled with a wireline formation tester or ultimately subjected to a drillstem test. Wireline formation testers are often unsuccessful in obtaining a hydrocarbon sample because of the extent of the invaded zone. The low oil saturation in the invaded zone has a low relative permeability resulting in little oil production and little, if any, movement while being sampled by a wireline tester tool until all of the invaded, water-based fluid has been removed.
The other fluid in the rock of interest is water. The value of the water resistivity in the virgin reservoir is needed to interpret the deep-reading resistivity tools. However, the water-based mud filtrate dilutes the in-situ water, making its characterization problematic. Some authors have proposed a method to tag the mud filtrate with radioactive tritium while coring the reservoir. The resulting core is sampled, its water extracted and analyzed for tritium. The measured concentration of tritium is used with the measured porosity to compensate the fluid properties for the effect of dilution from mud filtrate. Other methods use an uncommon anion as the tagged material to avoid radiation-based methods. The formation tester tool can also be used to obtain a water sample in the water leg of the reservoir. Although the zone is invaded with mud filtrate, we can use the pump-out feature available on all vendors’ tools to pump fluid from the invaded zone into the wellbore until the entire invasion has been removed. At this point, a water sample can be taken. The tester tool has an onboard water resistivity cell that is used to monitor the change in resistivity as the invasion fluid is pumped. When this value no longer changes, we switch over and take a water sample for analysis.
Oil-based drilling mud
The overwhelming presence of oil in this type of mud dilutes the hydrocarbon in the invaded zone to such a point that analysis of the hydrocarbon in sidewall samples can no longer be used to predict hydrocarbon fluid properties. On the other hand, the water phase is now intact and can be sampled and analyzed with usual methods.
To determine hydrocarbon properties, wireline formation testers must be used. Two methods are useful. One method requires that many judiciously placed pressure tests be taken in the wellbore. This will permit the determination of the fluid-pressure gradient and density, which can be used to identify gas, oil, or water. Another method requires the use of the pump-out feature available on all wireline vendor tester tools to pump invaded zone fluid into the wellbore until the invading fluid has been reduced to a sufficiently low value, and then switches the pump to capture fluids in a removable, transportable fluid chamber. The feature of these tester tools that makes this possible is onboard spectrometers that have the ability to discern oil-based mud filtrate from in-situ hydrocarbons that guide the changeover from pumping into the wellbore to the sample chamber. Pressure/volume/temperature laboratories for the required fluid properties can then analyze these fluids. The operation of wireline formation testers is neither cheap nor without risk of tool sticking; thus, some operators choose not to run these wireline tools and opt instead for a drillstem test. All wireline tester tools can be used to take a water sample in the water leg, and this practice is encouraged. Not only are errors in water resistivity reduced, but possible incompatibilities between in-situ water and completion fluids are discovered before completion attempts.
Hydrocarbon identification with acoustic logging
Acoustic coupling between solid and gas or fluid and gas is poor, resulting in a high loss of energy. A sudden loss of energy (amplitude) in the measured acoustic signal, primarily in the compressional wave and only secondarily in the shear wave: (e.g., the cycle skipping or high slowness values) may indicate gas-filled pore space (gas effect). In the cased of gas-filled porosity, the acoustic-neutron crossplot can be useful for this purpose because neutron porosity is lower than acoustic porosity in gas zones.
Compressional velocities are affected (slowed) by the compressive fluids in the pore space, while shear velocity is affected only by the rock matrix. Consequently, the presence of gas is especially noticeable in compressional-wave slowness. The combination of compressional and shear slowness, either as a ratio or as a log overlay, provides a quick-look gas indicator (Fig. 1).
The ratio of Vp/Vs offers a quicklook technique to distinguish between reservoir fluids and is especially effective in identifying light hydrocarbons (gas). When Δts is plotted against the Vp/Vs ratio, water-bearing sands and shales show a linear relationship and points falling below matrix lines result from the slowing effect of Δtp in light hydrocarbons (Fig. 2). These relationships are used for correcting porosity in gas-bearing intervals. Further, laboratory investigations suggest that the Vp/Vs ratio can be used for saturation determination in some situations as well as time-lapse changes accompanying steam flood of heavy-oil reservoirs.
Fig. 2 – Crossplot of shear slowness vs. Vp/Vs serves as a quick-look hydrocarbon indicator. Compressional-slowness travel times increase where the rock pore space is occupied by more compressible fluid (modified from original, courtesy of Baker Atlas).
Gas detection with Stoneley waves
Stoneley-wave properties, used in combination with other data, facilitate identification of gas-bearing intervals. A gas-saturated formation interval has drastically different fluid mobility and compressibility compared to those of the surrounding formations. In the presence of gas, Stoneley-derived permeability is overestimated because of increased pore-fluid mobility (decreased viscosity) and compressibility, and NMR permeability may be underestimated because of a decreased hydrogen index. If first calibrated in a nongas-bearing interval, separation of the two permeability curves indicates the presence of gas (Fig. 3). The plot also shows the neutron-density crossplot is effective in detecting the gas zone and may be more sensitive in some intervals.
The significant contrast in fluid mobility and compressibility in a gas zone also generates a measurable Stoneley-wave reflection. The presence of these reflections, together with an increase in compressional slowness or a decrease in the Vp/Vs ratio, identifies a gas-bearing zone (Fig. 4). This type of joint interpretation is particularly effective in thin-bed evaluation.
Fig. 4 – Gas detection in a high-porosity, laminated formation using thin-bed slowness and Stoneley reflection. The increase in P-wave slowness (Track 2) across the interval of thin gas ssands, X740 to X800 m, is accompanied by low density values (Track 2) and numerous Stoneley-wave reflections (Track 3) (courtesy of Baker Atlas).
Recent work suggests that the Vp/Vs ratio may also serve as an indicator of bypassed oil in cased wells. Research on the acoustic properties of heavy oils indicates that under the proper conditions of temperature and viscosity, these oils may behave as solids and generate shear waves that may be detectable at logging-tool frequencies.
Hydrocarbon typing with NMR logging
See separate article on Fluid typing with NMR logging
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- Hamada, G.M. 2004. Vp/Vs Crossplots Identify Reservoir Fluids. Oil & Gas J. 102 (24): 41–44.
- Khazanehdari, J., and McCann, C. 2005. Acoustic and Petrophysical Relationships in Low-Shale Sandstone. Geophysical Prospecting 53 (4): 447–462.
- Williams, D.M. 1990. The Acoustic Log Hydrocarbon Indicator, paper W. Trans., 1990 Annual Logging Symposium, SPWLA, 1–22.
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- Tang, X.M., Altunbay, M., and Shorey, D. 1998. Joint Interpretation of Formation Permeability from Wireline Acoustic NMR, and Image Log Data, paper KK. Trans., 1998 Annual Logging Symposium, SPWLA, 1–13.
- Tang, X.M. and Patterson, D. 2001. Detecting Thin Gas Beds in Formations Using Stoneley Wave Reflection and High-Resolution Slowness Measurements, paper OO. Trans., 2001 Annual Logging Symposium, SPWLA, 1–14.
- Gutierrez, M., Dvorkin, J., and Nur, A. 2000. In-Situ Hydrocarbon Identification and Reservoir Monitoring Using Sonic Logs, La Cira-Infantas Oil Field (Colombia), paper RPB 2.6. Expanded Abstracts, 2000 Annual Meeting Technical Program, SEG, 1727–1730.
- Gutierrez, M.A., Dvorkin, J., and Nur, A. 2001. Theoretical Rock Physics for Bypassed Oil Detection Behind the Casing—La Cira-Infantas Oil Field. The Leading Edge 20 (2): 192–198. http://dx.doi.org/10.1190/1.1438910
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