2 3 4
A
0 1
1,000 3 E 2 1 0 B A D C 1,200 1,400 1,600 1,800 Wavelength, nm F 2,000 2,200 2,400 B
F 3 E C D 2 D 1 0
Laser source
500 600 E F 700 Wavelength, nm C 800 900
A B
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1,200
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1,800 Wavelength, nm
> Fluorescence measurement and emulsions. Surface laboratories use centrifuges and chemical agents to break down emulsions and measure properties of the native hydrocarbons. NIR measurements from six heavy-oil emulsion samples are shown before (top left) and after (bottom left) attempts at demulsification. Emulsion Samples D, E and F exhibit strong light scattering, which produces a shift in their optical densities. There is also a noticeable water peak after 2,200 nm. Samples B (yellow) and D (green) have different spectral signatures as emulsions, yet the oil portions are similar after demulsification based on their optical characteristics. Downhole optical spectroscopy measurements have no provision for demulsification. However, the fluorescence measurement spectrum is unaffected by the emulsion (right), and the responses are identical to those of demulsified oils (not shown). Fluorescence spectra of Samples B and D clearly indicate the oils in the emulsion are similar in type, which is not apparent in the optical spectroscopy data from emulsified samples. (Adapted from Andrews et al, reference 20.)
2,000
2,200
2,400
tively independent of the state of the emulsion and gives a qualitative indicator of oil type (above). This is particularly useful in identifying compositionally graded fluids in heavy-oil reser- voirs, such as those affected by biodegradation, without the requirement of pumping to obtain an emulsion-free sample.21 Another important property of reservoir fluids
is water pH. The pH of water is used for predicting scaling and corrosion potential and for petrophys- ical evaluation, and it can also contribute impor- tant information about reservoir connectivity.22 The measurement concept is similar to that of classroom experiments, in which the color change in litmus paper indicates the pH of a liquid. For the InSitu pH measurement, a colorimetric dye is injected directly into the flow stream where the optical spectrometer detects the color change. Making the measurement downhole is important because irreversible changes can occur when water samples are brought to the surface for labo- ratory testing. The measurement not only reflects the condition of the water at formation tempera- ture and pressure, but also includes the effects of
hydrogen sulfide [H2S] and CO2. Typically, these gases are flashed and missing when water is ana- lyzed at surface conditions. Errors in measure- ment caused by precipitation of pH-altering solids, which can occur at lower temperatures, are also overcome. The InSitu pH measurement has proved use-
ful in differentiating WBM filtrate from connate water. Filtrate from WBM systems is generally basic, with a pH range from 8 to 10, and formation waters are usually more acidic. In the past, resis- tivity of the fluid was used to identify formation water, but this method is not effective when the resistivity of the WBM filtrate is similar to that of the connate waters. Engineers use the pH sensor to detect fluid transitions and contacts. The conventional method for determining
Oilfield Review Autumn 09
FluidsLab Fig. 10 ORWIN09/10-FluidsLab Fig. 10
fluid transitions and contacts is plotting MDT pressure data versus depth. Although this method is widely used, its precision depends on the abil- ity to measure true formation pressure. Pressure- gradient plots may be affected by the number and spacing of pressure points, measurement accu- racy, depth accuracy and freedom from external
perturbations that include supercharging, tool movement and tool seal failures. In addition, it is often difficult to establish pressure gradients in layered reservoirs with varying permeability, formations containing viscous oils and rocks of low permeability.23 The InSitu Density measurement overcomes
many of the limitations inherent in pressure plots. Live-fluid density data are acquired from two independent sensors, one placed in the sam- ple probe and the other located in the flowline. Profiling the fluid density quantifies the varia- tions in fluids versus depth. Compartmentalization, sealing elements and
barriers to flow can be identified from abrupt changes in fluid properties. The accuracy and resolution of the data make it possible to com- pare fluids from different wells within a field, establishing connectivity or lack thereof. The InSitu Density sensor can be placed in the fluid analyzer section as well as in the Quicksilver Probe tool, providing independent confirmation of the measurement.24
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Oilfield Review
Optical density
Optical density
Fluorescence intensity
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