Phase change analysis in logging method

An improved method of fluid analysis in the borehole of a well. A fluid sampling tool is fitted with a pumpout module that can be used to draw fluids from the formation, circulate them through the instrument, and then expel this fluid to the borehole. It has been determined that certain measurements would be most valuable to implement down hole, such as the formation fluid bubble point and dew point. Accurate bubble point and dew point measurements are made by forming bubbles or a liquid drop in a measured sample, and detecting same.

FIELD OF THE INVENTION 
The present invention relates to down hole fluid sampling tools and methods 
and, more particularly, to an improved fluid extraction tool and method 
for analyzing thermodynamic phases of complex fluids down hole. 
BACKGROUND OF THE INVENTION 
Schlumberger Technology Corporation, the assignee of the present invention, 
has pioneered the use of Modular Formation Dynamics Testers (MDTs) and 
other down hole tools. The Modular Formation Dynamics Tester is one of 
several very useful instruments for obtaining formation fluid samples. The 
MDT tool is suspended by a wire line and then lowered into the borehole of 
the well. The instrument is secured to the walls of the borehole and 
samples of the formation fluid are extracted. Such a tool is illustrated 
in U.S. Pat. No. 4,860,581, issued to Zimmerman et al on Aug. 29, 1989. 
Fluid sampling tools comprise a pumpout module that can be used to draw 
fluids from the formation, circulate them through the instrument for 
analysis, and then expel these fluids to the borehole. The MDT can also 
retain samples of formation fluids in sampling bottles, which are then 
transported to the surface. The samples are transferred at the surface 
from the sampling bottles to transportation bottles. The formation fluid 
samples are then sent to pressure-volume-temperature laboratories (PVT 
labs) for analysis of their composition and their physical properties. 
Conventional PVT labs provide a broad range of measurements and services. 
It is essential to know the bubble point of crude oil, because when the 
borehole pressure drops below the bubble point pressure during production, 
gas bubbles form in the porous rock reservoir. This dramatically decreases 
the oil phase relative permeability. Knowledge of the bubble point is also 
useful in determining the composition of the hydrocarbon mixture in the 
reservoir. 
The best current practice of measuring bubble point is to bring a sample of 
fluid to the surface to be sent to a laboratory. There, the sample is 
placed in a cylinder, the volume of which is increased by a piston. 
Pressure is monitored by a gauge. The bubble point is normally considered 
to be the pressure at which a break (knee) appears in the pressure versus 
volume (P-V) curve. 
However, this technique has several disadvantages. It is time consuming to 
bring a fluid sample to the surface, transfer it to the (possibly distant) 
laboratory, and await the result. Further limitations of this technique 
are: (1) only a few samples (typically six or fewer) can be transported to 
the surface on each tool run; (2) samples are altered by pressure and/or 
temperature changes when they are brought to the surface; (3) sample 
composition can change as a result of imperfect transfer from sampling 
bottle to transportation bottle, and to laboratory apparatus; (4) 
typically, a delay of several weeks occurs between the time of fluid 
sampling and the receipt of the laboratory report; (5) it is not known 
whether the sample and data are valid until long after the opportunity to 
take further samples passes; (6) high pressure, toxic, explosive samples 
must be transported, handled by wellsite and laboratory personnel, and 
disposed of, creating numerous potential health, safety and environmental 
problems. 
The break in the aforementioned P-V curve is unreliable for determining the 
bubble point. A more reliable method is to observe bubble formation in the 
cylinder by use of a sight glass. In this manner, bubbles may be detected 
visually. They may also be measured by the transmission of near infrared 
light, since the bubble point is associated with attenuation of the light 
beam. 
A number of down hole measurement techniques have been proposed for making 
a bubble point measurement within a down hole tool. These methods are 
described in U.S. Pat. Nos. 5,329,811; 5,473,939; 5,587,525; 5,622,223; 
and 5,635,631. 
As described in the above-mentioned patents, fluid is isolated in the flow 
line, and then a pump (the same one used to extract fluid from the 
formation) is used to expand the volume. A pressure gauge is used to 
monitor the P-V curve. 
Several problems exist with these prior art methods of determining bubble 
point. First, the measurement is very time consuming. At each stage of the 
expansion, it is necessary to allow bubbles to nucleate. 
In U.S. Pat. No. 5,635,631, a gas is formed slowly, "relative to the amount 
of time taken to expand the sample." A full bubble point determination can 
require over an hour. Identifying a single pressure, following the maximum 
expansion, as the bubble point pressure, is clearly inaccurate, since it 
assumes that the compressibility of the hydrocarbon below the bubble point 
pressure is negligible. This assumption is erroneous, and can lead to 
substantial errors in bubble point pressure determination. 
To detect phase changes of complex hydrocarbon mixtures, it is necessary to 
nucleate bubbles or drops of the new phase and to detect these bubbles. In 
standard laboratory apparatus, and in prior art down hole tools, the 
bubbles or drops are formed at arbitrary locations in the fluid volume, 
and then detected by pressure-volume measurements, or by detecting bubbles 
at another site (e.g., in the beam between a source and detector of 
light). Both of these methods are characterized by a delay between the 
arrival at the thermodynamic phase line and the initiation of phase 
change, and then a delay between the phase change and its detection. The 
methods and tools of this invention solve both problems. 
In a related prior art publication [SPE 30610 (1995) Michaels (Western)] a 
technique is described in which the volume is increased as the pressure is 
monitored. Special significance is attached to the pressure at which the 
P-V curve departs from linearity. The authors cautiously declined to call 
this pressure the bubble point. This criterion may aid in collecting a 
sample for surface analysis, but it is not helpful in planning reservoir 
operations. This pressure may underestimate the bubble point, if the 
appearance of bubbles is delayed by retarded nucleation. Thus, maintaining 
the production pressure at this level during oil production may lead to 
formation of gas in the formation, and thus reduced productivity. 
The present invention addresses a method of providing a down hole method of 
making rapid, accurate measurements of bubble point using a down hole 
tool, such as an MDT tool. 
The dew point is the most important thermodynamic parameter associated with 
gas condensate reservoirs. Gas condensate reservoirs produce gas at high 
pressure. As the pressure drops, liquid is formed. When this happens in 
the pore space of the rock, the permeability to gas flow is greatly 
reduced, with accompanying loss of production. Therefore, it is important 
to maintain the pressure of gas condensate reservoirs above the dew point 
for as long as possible. 
Sensors have been developed to measure the dew point of ordinary humid air. 
A cooled plate provides a definite location for the nucleation of liquid 
drops. The plate is part of a mass-sensitive sensor, such as an acoustic 
surface wave resonator, which detects the first presence of the liquid. H. 
Ziegler and K. Rolf, "Quartz Sensor for Automatic Dew-Point Hygrometry", 
Sensors and Actuators, Vol. 11, pp. 37-44 (1987). 
Devices of this kind will often fail when used to measure the dew point of 
gas condensates under down hole conditions. This is so, because mixtures 
of hydrocarbons found in reservoirs can have unusual phase diagrams. As 
the pressure is reduced, the first condensation of liquid can occur at 
either the hottest or the coldest point accessible to the mixture. Amyx, 
Bass, Whiting, "Petroleum Reservoir Engineering", McGraw-Hill, 1960, pp. 
220-229. 
SUMMARY OF THE INVENTION 
In accordance with the present invention, there is provided an improved 
method of fluid analysis in the borehole of a well. Fluid sampling tools 
as well as other down hole tools can be used to measure the bubble point 
and dew point of the extracted fluids. For example, an MDT tool comprises 
a pumpout module that can be used to draw fluids from the formation, 
circulate them through the instrument, and then expel this fluid to the 
borehole. It has been determined that bubble point and dew point 
measurements can be measured accurately with a down hole tool, such as an 
MDT. 
To detect phase changes of complex hydrocarbon mixtures, it is necessary to 
nucleate bubbles or drops of the new phase and to detect these bubbles. In 
standard laboratory apparatus, and in prior art down hole tools, the 
bubbles or drops are formed at arbitrary locations in the fluid volume, 
and then detected by pressure-volume measurements, or by detecting bubbles 
at another site (e.g., in the beam between a source and detector of 
light). Both of these methods are characterized by a delay between the 
arrival at the thermodynamic phase line and the initiation of phase 
change, and then a delay between the phase change and its detection. 
The solution proposed by this invention is to use an ultrasonic transducer 
in the fluid flowline to create bubbles by cavitation. Cavitation, 
however, is generally considered to be impossible when fluid pressure is 
high. Although several hundred psi is a rule of thumb for typical 
piezoelectric ultrasonic transducers, the pressure in the sampling tool 
flowline is as high as 20,000 psi. Therefore, it would appear that 
cavitation is not a viable method of creating bubbles down hole. However, 
for a fluid at the bubble point (i.e., the point at which bubbles are 
thermodynamically stable, but form slowly), modest localized pressure 
reductions, such as are found in acoustic waves, can lead to efficient 
evolution of bubbles. 
The bubbles thus formed are detected at the site where they are produced by 
monitoring the ultrasonic properties of the liquid. This is conveniently 
done by monitoring the acoustic impedance of the ultrasonic transducers 
used to cavitate the fluid. At the first appearance of a bubble, even a 
transient bubble, the acoustic impedance mismatch between transducer and 
fluid is greatly altered. This in turn produces a change in the electrical 
impedance of the transducer. 
Another method of nucleating bubbles at the bubble point is to provide 
predetermined locations in the fluid volume at which the temperature 
differs incrementally from that of the main body of liquid. For ordinary 
liquids, bubbles are preferentially formed where local hot spots occur in 
the liquid. 
Crude oils differ from ordinary liquids in that they can have unusual phase 
diagrams. For some crudes, bubbles form preferentially at cold spots in 
the liquid volume. Thus, in order to be certain that the bubble point is 
accurately measured for all kinds of crude oils and crude oil mixtures, 
both a hot and a cold spot should be provided. A transducer placed in 
proximity to these hot and cold locations can sensitively detect the first 
appearance of bubbles. 
No strong signature appears in the P-V characteristic at the dew point, 
because the first appearance of liquid does not substantially change the 
compressibility of the mixture. Therefore, it is necessary to sense the 
liquid phase directly. To do this, the first condensation must be on a 
moisture sensor. 
Dew point sensors are normally integrated with coolers so that the first 
condensation occurs on the sensor. However, mixtures of hydrocarbons found 
in reservoirs can have unusual phase diagrams: condensation can occur at 
the hottest point accessible to the mixture. Amyx, Bass, Whiting, 
"Petroleum Reservoir Engineering", McGraw-Hill, 1960, pp. 220-229. Thus, 
moisture sensors must be mounted on both a heater and a cooler in order to 
ensure that the dew point will be measured accurately under all 
circumstances. 
The method of the invention consists of the following steps: 
a) withdrawing a fluid sample from the formation fluid using a formation 
sampling tool, such as an MDT; 
b) closing valves in a flowline of the formation sampling tool in order to 
establish a well-defined sample volume; 
c) expanding this sample volume in step-by-step fashion (i.e., 
incrementally moving a piston of the pumpout module of the formation 
sampling tool); 
d) nucleating bubble formation or a drop of liquid at a predetermined site 
in the sampled volume; 
e) observing an onset of bubble formation or a drop of liquid at the 
predetermined site; and 
f) measuring pressure of fluid at the onset of bubble formation or a drop 
of liquid, which pressure measurement defines the bubble point or the dew 
point.

DESCRIPTION OF THE PREFERRED EMBODIMENT 
Generally speaking, the present invention features a method of determining 
the bubble point and dew point of formation fluids down hole. Extracting 
fluids from earth formations by means of sampling logging tools is widely 
known and practiced. "Schlumberger Wireline Formation Testing and 
Sampling" (1996). The best known commercial tools used for this purpose 
are the Schlumberger Modular Formation Dynamics Tester (MDT) and the 
Western-Atlas Reservoir Characterization Instrument (RCI). 
Now referring to FIG. 1, a typical MDT tool 10 having a PVT module 11 is 
shown. 
For purposes of definition herein, tools that extract fluids from 
formations are generically called "sampling tools". Most commonly, 
sampling tools pump formation fluid for a substantial period of time in 
order to minimize contamination by mud filtrate. The MDT tool 10 has a 
pumpout module 12 for this purpose. During the pumping process, fluid 
properties are measured by various means, such as low-frequency electrical 
conductivity (MDT and RCI), dielectric constant (RCI) and/or optical 
properties (MDT). In the initial stage, this fluid is discarded by being 
pumped either into the borehole or back into the formation at a remote 
point. The fluid is redirected to one or more sample bottles in the sample 
module 14; subsequently, the fluid is transported in such bottles to the 
surface for extensive examination and testing, when contamination has been 
minimized. Alternatively, measurements of bubble point can be made inside 
the tool by the aforementioned patented methods. 
There are two main problems with prior art, down hole bubble point and dew 
point measurements: the measurements are slow, and the measurements are 
inaccurate. The bubble point or dew point measurements are relatively time 
consuming. The bubble point measurement is impeded by bubbles that do not 
readily form at the thermodynamic bubble point of the liquid. Even when 
the gas phase is thermodynamically stable at a given temperature and 
pressure, a gas bubble may be unable to form because its surface free 
energy exceeds the free energy difference of the bulk phases. This 
phenomenon accounts for supercooling or superheating and is generally 
observed at first order phase transitions, described by classical 
nucleation theory. A. W. Adamson, "Physical Chemistry of Surfaces", 3rd 
edition, Wiley, chap. 8, 1976. In order to minimize the error associated 
with nucleation, bubble point measurements are made by changing the volume 
very slowly, typically over an hour. 
Chemists have found that liquid-to-gas transitions can be observed more 
reproducibly when the liquid is stirred, but implementing that technique 
in the flowline of a down hole sampling tool would compromise reliability. 
Thus, the stirring procedure is not a preferred solution. 
Referring to FIG. 2, there is shown a typical phase diagram characterizing 
a gas condensate reservoir. The horizontal axis is temperature and the 
vertical axis is pressure. When a reservoir is first penetrated by a 
borehole, the reservoir is characterized by its original temperature and 
pressure. Two possible original states are shown, at Points 1 and 2. To 
bring the reservoir into production, the pressure is reduced at constant 
temperature. Thus, reservoir production is represented by movement down 
vertical lines in FIG. 2. 
In order to maintain maximum permeability to hydrocarbon flow, it is 
essential that only one fluid phase exist in the formation. This means 
that the pressure must remain above the Dew Point Line shown in FIG. 2. 
Above this line, only gas exists; below the Dew Point Line, liquid 
condenses, forming a two-phase mixture in the rock pores of the earth 
formation. The presence of two phases decreases permeability to fluid 
flow, and therefore reduces production rate. 
To detect the dew point pressure at down hole temperature using a fluid 
sampling tool, a sample of formation fluid is drawn into the tool at a 
pressure as close to formation pressure as possible. The sample in the 
tool is then isolated and the pressure reduced in a controlled manner, as 
described herein. When the dew point is reached, liquid condenses. 
Ordinary dew point sensors used to measure atmospheric humidity are 
thermostated at a temperature slightly below the ambient temperature. The 
same technique is appropriate for reservoirs characterized by initial 
temperature and pressure conditions exemplified by Point 2 (FIG. 2). 
Condensation first appears at the cooled sensor, giving a reliable 
measurement of the dew point. 
However, for gas condensate reservoirs characterized by initial conditions 
exemplified by Point 1 (FIG. 2), prior art sensors yield erroneous 
results. In that case, the cooled sensor is the last place in the volume 
on which liquid condenses. Therefore, it is necessary for the sensor to be 
placed at the warmest point in contact with the fluid to be tested. Liquid 
first condenses on the warm sensor, which therefore detects the first 
droplet of liquid resulting from the pressure reduction. 
Referring now to FIG. 3, a typical phase diagram is illustrated of a crude 
oil reservoir with significant dissolved gas content. Once again, the 
horizontal axis is temperature and the vertical axis is pressure. When a 
reservoir is first penetrated by a borehole, the reservoir is 
characterized by its original temperature and pressure. Two possible 
original states are shown, at Points J and K. To bring the reservoir into 
production, the pressure is reduced at a constant temperature. Thus, 
reservoir production is represented by movement down vertical lines in 
FIG. 3. 
As aforementioned, in order to maintain maximum permeability to hydrocarbon 
flow, it is essential that only one fluid phase exist in the formation. 
This means that the pressure must remain about the Bubble Point Curve 
shown in FIG. 3. Above this line, gas is completely dissolved in the oil; 
below the Bubble Point Curve, gas comes out of solution, forming a 
two-phase mixture in the rock pores of the earth formation. The presence 
of two phases decreases permeability to fluid flow, and therefore reduces 
production rate. 
To detect the bubble point pressure at down hole temperature using a fluid 
sampling tool, a sample of formation fluid is drawn into the tool at a 
pressure as close to formation pressure as possible. The sample in the 
tool is then isolated and the pressure reduced in a controlled manner as 
described herein. When the bubble point is reached, free gas appears in 
the oil. 
For many fluid mixtures, bubbles first appear in the fluid at the hottest 
point in the volume. In these fluids, a heater can be used to nucleate gas 
at a predetermined location. The same technique is appropriate for 
reservoirs characterized by initial temperature and pressure conditions 
exemplified by Point J (FIG. 3). 
However, for those reservoirs characterized by initial conditions 
exemplified by Point K in FIG. 3, the warmest point is the last place in 
the volume at which bubbles form. Therefore, it is necessary for the 
bubble sensor to be placed at the coldest point in contact with the fluid 
to be tested. 
Cavitation avoids the need to provide hot or cold points in bubble point 
cells. Bubbles first form at the location where sonic amplitude is 
greatest. Bubbles at the same place are readily detected by sonic means. 
Referring to FIG. 5, it will be observed that for a complex hydrocarbon 
mixture at constant temperature, a distinct slope change may occur at the 
bubble point. However, this may not always be the case, as seen by the 
pressure-volume curve illustrated in FIG. 4. 
The solution proposed by this invention is to use an ultrasonic transducer 
to create bubbles by cavitation. Cavitation, however, is generally 
considered to be impossible when fluid pressure is high. Although several 
hundred psi is a rule of thumb for typical piezoelectric ultrasonic 
transducers, the pressure in the sampling tool flowline is as high as 
20,000 psi. Therefore, it would appear that cavitation is not a viable 
method of creating bubbles down hole. However, for a fluid at the bubble 
point (i.e., the point at which bubbles are thermodynamically stable, but 
form slowly), modest localized pressure reductions, such as are found in 
acoustic waves, can lead to efficient evolution of bubbles. 
Various means may be used to induce cavitation, such as flow restrictions 
and propellers. The ultrasonic method is particularly suitable for 
sampling tools. The transducer may form part of the wall of the flowline. 
Deployed in such a manner, it does not interfere with other objectives of 
the sampling tool that rely on the unimpeded flow of fluid through the 
flowline. It is also relatively immune from erosion and has no moving 
parts, which are important considerations in down hole tools. 
It is as important to sense the presence of bubbles as it is to generate 
them. Laboratory studies have shown that the pressure versus volume curve 
can be an unreliable bubble point indicator for many crude oils, as 
aforementioned. Thus, means (e.g., optical means) have been devised to 
sense the presence of bubbles directly. Such sensors can probe only a part 
(often only a small part) of the total volume of fluid, so these means 
depend on the bubbles being transported to the site of the sensor. This is 
one purpose of the stirring process often used in laboratories. A stirring 
mechanism can be a failure-prone component in a fluid sampling tool, and 
hence it is not included in the preferred mode of transporting samples to 
the site of a bubble sensor. 
The solution proposed by this invention is to sense bubbles at the site at 
which they are produced. That is, bubbles are sensed at the location of 
the ultrasonic transducer used for cavitation. The acoustic impedance 
sensed by the ultrasonic transducer is extremely sensitive to the presence 
of bubbles, so bubbles can be produced and sensed at the same site, with 
very high reliability. The pressure of the fluid at which bubbles are 
first generated by the ultrasonic transducer is measured by a precision 
gauge, such as the Schlumberger CQG quartz pressure gauge. 
The acoustic impedance of a material is defined as the product of its mass 
density and sound speed. In one implementation of the invention, the 
acoustic impedance of the transducer is approximately matched to the 
acoustic impedance of the fluid, in the absence of bubbles. At the first 
appearance of a bubble, both the density and the sound speed of the fluid 
decrease. The transducer and fluid are no longer impedance matched 
acoustically. Under this condition, the electrical impedance of the 
transducer increases. 
Referring to FIG. 6, there is shown a simple electrical circuit used to 
monitor the electrical impedance of the transducer. An electronic 
oscillator 101 drives alternating current through a resistor 102 (having 
fixed resistance, R) and an acoustic transducer 103. Transducer 103 
radiates sound energy into fluid 104. 
The current in the circuit, I, is monitored by using a high-impedance 
voltmeter 105 to measure the voltage, V.sub.r, across resistor 102. Ohm's 
Law states that I=V.sub.r /R. 
The voltage across transducer 103, V.sub.t, is monitored by a second 
voltmeter 106. The electrical impedance of the transducer 103 is Z=V.sub.t 
/I=(V.sub.t /V.sub.r)R. 
When the acoustic impedance of the transducer is matched to the acoustic 
impedance of the fluid, in the absence of bubbles, the voltage across the 
transducer is relatively low; the current is relatively high. Thus, the 
electrical impedance of the transducer is relatively low. 
When the acoustic impedances of transducer and fluid are mismatched, 
however, in the presence of bubbles, the voltage across the transducer 
increases and the current decreases, increasing the electrical impedance. 
Referring to FIG. 7, a flow chart 20 is illustrated for the method of 
making a bubble point measurement, in accordance with the invention. The 
down hole fluid that is free of contamination is admitted into the tool, 
step 22. A valve in the tool is closed, step 24, in order to define a 
given volume. An ultrasonic transducer or other cavitation means is then 
enabled, step 26. The pressure and temperature of the sample fluid is 
measured, step 28. Then, the transducer is monitored to detect the 
presence of a bubble, step 30. If the bubble is detected, the bubble 
pressure is recorded, step 40. The cavitation source is then disabled, 
step 42, and the sampled fluid is expelled to the borehole, step 44. If a 
bubble is not detected for the given pressure and temperature, step 30, 
then the volume is increased by moving the piston of the sampling module, 
step 36. The sample is then remeasured for pressure and temperature, step 
28. The detection process, defined by steps 30 through 44, is then 
repeated. 
Referring to FIG. 8, an apparatus 50 for measuring the dew point down hole 
is illustrated. The fluid being sampled is drawn into a chamber 52 through 
a flow line 54 and inlet valve 56. The pressure gauge 58 measures the 
pressure in chamber 52. The pressure in the chamber 52 can be adjusted by 
piston 51. The temperature is also measured by suitable means (not shown). 
The Peltier cooler 60 reduces the temperature of the fluid at a selected 
site in chamber 52, while the heater 62 raises the temperature at another 
site. Liquid sensors 64 disposed at each site are used to detect the 
formation of a drop of liquid. After the measurements are taken, the 
sample is discharged to the borehole through the outlet valve 66 and 
flowline 68. 
Referring to FIG. 9, the method of measuring the dew point in accordance 
with the invention is illustrated by the flow chart 80. The fluid is 
admitted into the chamber 52, step 82. The valve 56 is closed to define 
the volume in chamber 52, step 84. The heater 62 and the cooler 60 are 
enabled, step 86. Pressure and temperature are measured, step 88. The 
sensors 64 monitor the presence of a liquid drop, step 90. If droplets are 
detected, then the dew point is recorded, step 94, the heater and cooler 
are disabled, step 96, and the fluid sample is expelled to the borehole, 
step 98. If no droplets are detected, step 90, then the volume of the 
fluid in chamber 52 is increased, step 93, and pressure and temperature 
are again measured, step 88. Then steps 90 through 98 are repeated. 
Since other modifications and changes varied to fit particular operating 
requirements and environments will be apparent to those skilled in the 
art, the invention is not considered limited to the example chosen for 
purposes of disclosure, and covers all changes and modifications which do 
not constitute departures from the true spirit and scope of this 
invention. 
Having thus described the invention, what is desired to be protected by 
Letters Patent is presented in the subsequently appended claims.