Download Downhole Optical Analysis of Formation Fluids- Disk 2

Downhole Optical Analysis of
Formation Fluids
Rob Badry
Calgary, Alberta, Canada
Derrel Fincher
Sugar Land, Texas
Oliver Mullins
Bob Schroeder
Ridgefield, Connecticut, USA
(FT) Formation (RFT) Repeat
Tester
Formation Tester
1955
1975
Tony Smits
Fuchinobe, Japan
(MDT) Modular Formation
Dynamics Tester
1992
In the past, wireline formation
samplers have not been able to
see the fluid they were sampling.
Electric power
module
Downhole optical analysis of fluid
before sampling removes the
Hydraulic
power module
blindfold to reveal oil, water or
gas. The sample chamber needs
to be opened only when the
Probe module
desired fluid is present.
Bringing formation fluid samples to the surface for examination was a novel wireline
advance when it was introduced in the early
1950s (right ). Run in open hole or cased
hole, the Formation Tester (FT) took a sample of formation fluid where analysis of earlier runs of resistivity and porosity logs
showed promising zones. The FT consisted
of a sealing packer and probe system that
could be set against the formation. Once
this was set and opened, formation fluid
drained into a sample chamber. The entire
sampling operation, from set to retract, was
monitored using a pressure gauge. The sample chamber was closed only when pressure
stopped increasing—implying the chamber
was full and at formation pressure.1
For help in preparation of this article, thanks to Hifzi
Ardic, Schlumberger Wireline & Testing, Montrouge,
France and Robert Gabb, Schlumberger Wireline & Testing, Livingston, Scotland.
MDT (Modular Formation Dynamics Tester), OFA (Optical Fluid Analyzer) and RFT (Repeat Formation Tester)
are marks of Schlumberger.
1. Finklea EE: “Use of Pressure Buildup Curves from the
Formation Tester for the Evaluation of Permeability
and Reservoir Pressure,” The Technical Review 9,
no. 3 (August 1958): 30-35.
January 1994
Dual-probe
module
Flow control
module
OFA Optical
Fluid Analyzer
module
Multisample
module
Dualpacker
module
nEvolution of wireline formation
testers. The Formation Tester (FT) had
a pressure gauge to
monitor sampling
into a single chamber. Pretest chambers introduced with
the RFT Repeat Formation Tester tool
allowed a check on
seal integrity and
gave an indication
of permeability
before sampling into
one of two chambers. The introduction of the dualpacker module, with
the MDT Modular
Formation Dynamics
Tester tool, allows
sampling when seal
failure might be a
problem. The
pumpout module is
used along with the
OFA Optical Fluid
Analyzer module to
confirm the presence
of desired formation
fluid before one of
several sample
chambers is opened.
Sample
module
Sample
module
Pumpout
module
21
The FT’s probe and packer could be set
only once per trip in the hole. This created a
couple of problems. If the formation has low
permeability, the sample chamber could
take hours to fill, delaying rig operations
and increasing the risk of the tool becoming
stuck. Sampling in low-permeability formations was therefore often aborted. But sampling also had to be aborted if the seal
between packer and borehole wall failed,
indicated by a sudden increase in sampling
pressure to hydrostatic. The only remedy
was to pull out of the hole, redress the tool
and try again. The next generation of testers
addressed these difficulties.
The RFT Repeat Formation Tester tool,
introduced in the second half of the 1970s,
allowed an unlimited number of settings or
pretests before sampling was attempted.
Pretest chambers were used to indicate the
permeability and to check for seal failures.
During a pretest two small volume chambers opened producing pressure drawdowns. Knowing the amount of drawdown
for each chamber gave two estimates of permeability. Once the pretest chambers were
filled, formation permeability could also be
calculated from the subsequent buildup to
formation pressure. 2 Sudden increase to
hydrostatic pressure during a pretest showed
seal failure. Testing the formation first
allowed sampling to be carried out in zones
where seal failures did not occur and where
permeabilities were high enough to allow
one of two sample chambers to be filled in
a reasonable amount of time.
However, RFT samples suffered important
limitations: the sample too often contained
a large percentage of mud filtrate and the
flowing pressure sometimes dropped below
bubblepoint changing the sample characteristics. Even when the sample was formation
fluid, it could have been water or gas and of
no interest to the oil company. These drawbacks frequently led to expensive and timeconsuming operations, to say nothing of
frustration caused by the absence of anticipated information or the presence of data
later found to be useless. The latest generation formation tester, the MDT Modular Formation Dynamics Tester tool, overcomes
these problems.3
22
The MDT Tool
How the OFA module works
In the MDT tool, unwanted fluid is expelled
from the tool using the pumpout module.
During sampling, the engineer can monitor
the resistivity and temperature of fluid in the
flowline while pumping it directly into the
borehole or into a dump chamber. When
fluid quality is judged to be representative
of the reservoir, the pump is stopped and
pure formation fluid can be diverted to the
sample chamber or, if a sample is not
required—often the case when formation
water or gas is indicated—another zone can
be tested.
To prevent gas from coming out of solution during sampling, pressure is maintained
above bubblepoint using throttle valves in
the sample chambers controlled by surface
software. Maintaining pressure above bubblepoint reduces drawdown, which helps
prevent crumbling in soft formations. Excessive drawdown can result in seal failure and
hence mud contamination of a sample.
Drawdown can also be limited by using a
water cushion and choke with the multisample module.
Formations in which seal failures are
likely—highly laminated or otherwise heterogeneous formations—or formations that
have low permeability can be tested and
sampled using the dual-packer module.
Instead of a probe and packer to provide a
seal, two inflatable packers are used to isolate an interval of about 3 ft [1 m] of formation forming a mini drillstem test. The
pumpout module is used to inflate the packers and also to expel mud from between the
packers before sampling.
Are all the sampling problems solved?
Not quite! Resistivity will show transitions
only if there is a resistivity contrast between
fluids. And, in the presence of more than
one phase, the interpretation can be dominated by the continuous phase, making
sampling decisions difficult. Also, keeping
gas in solution by controlling flowing pressure is possible only if the bubblepoint pressure is known. If bubblepoint pressure is not
known, sampling pressure may be too low
and the sample could be spoiled by the
presence of free gas. A more complete analysis of flowline fluid is therefore needed.
Providing a solution for these particular
problems is the recently introduced OFA
Optical Fluid Analyzer module of the MDT
tool. As fluids flow through the MDT‘s flowline, real-time interpretation of the measurements indicates the proportions of oil and
water, and gives a qualitative indication of
free gas.4
The flowline passes through two independent optical sensors (next page, top). In one
cell, absorption spectroscopy is used to
detect and analyze liquid, while in the other
cell, a special type of optical reflection measurement detects gas. This allows wellsite
personnel to decide whether to divert the
flow into a sample chamber for retrieval,
continue to expel it into the borehole or into
a dump chamber, or to increase the sampling pressure above bubblepoint. It has
also been used to verify that the formation
contains only water or only gas and that a
sample is not required. Thus, the sample
chambers in the tool are kept available for
desired fluids only. Even when oil-base mud
is used, it is possible to track the transition
from borehole mud, to filtrate, to connate
oil as long as the two oils differ in color.
After a decision has been made to switch
from pumpout to sampling, the OFA module continues to monitor the fluid in the
flowline in particular to verify that production remains above bubblepoint.
A field test in a vuggy carbonate formation, where conventional probe seals are
difficult to obtain, used the OFA module
along with several other features of the
MDT tool.5 The inflatable dual-packer module isolated the test interval, and the OFA
module indicated the fluid in the flowline
throughout the test (next page, bottom ).
After a pretest to check permeability and
seal integrity, 44,000 cm3 [10 gallons] of
fluid were pumped through the OFA module using the pumpout module. OFA analysis shows that the fluid changes from borehole mud to filtrate to oil as pumping
proceeds. After about an hour, pumpout
into the borehole above the packers was
stopped and flowline fluid was diverted to
the sample chamber for collection. The
throttle valve at the chamber end of the
flowline maintained pressure above the
bubblepoint during sampling.
2. Stewart G and Wittmann M: “Interpretation of the
Pressure Response of the Repeat Formation Tester,”
paper SPE 8362, presented at the 54th SPE Annual
Technical Conference and Exhibition, Las Vegas,
Nevada, USA, September 23-26, 1979.
3. Colley N, Hastings A, Ireland T, Joseph J, Reignier P,
Richardson S, Traboulay I and Zimmerman T: “The
MDT Tool: A Wireline Testing Breakthrough,” Oilfield
Review 4, no. 2 (April 1992): 58-65.
Badry R, Head E, Morris C and Traboulay I: “New
Wireline Formation Tester Techniques and Applications,” Transactions of the 34th SPWLA Annual Logging Symposium, Calgary, Alberta, Canada, June 1316, 1993, paper ZZ.
4. Smits AR, Fincher DV, Nishida K, Mullins OC,
Schroeder RJ and Yamate T: “In-Situ Optical Fluid
Analysis as an Aid to Wireline Formation Sampling,”
paper SPE 26496, presented at the 68th SPE Annual
Technical Conference and Exhibition, Houston, Texas,
USA, October 3-6, 1993.
5. Badry R et al, reference 3.
Oilfield Review
Light-emitting
diode
Gas detector
Lamp
nThe OFA module
with its two sensor
systems, one for
liquid detection
and analysis, and
the other for gas
detection.
Fluid flow
Liquid detector
Time
(sec)
Pumpout Module
Optical Fluid Analyzer
Pumpout Volume
Highly Absorbing Fluid
0.0
10000.0
cm3
720
Comments
Oil
Water
Set packer
Packer pretest
1440
Start pumpout
Pumping filtrate
2160
nOFA log display
during sampling
using the dualpacker module.
Starting at the top
of the display, a
pretest confirms
the seal, followed
by pumpout of
44,000 cm3 of fluid
from the packerisolated interval.
The OFA display—
second track from
the right—shows
flowline fluid
change from filtrate to oil. Flow is
then diverted to a
1-gallon sample
chamber with
throttle control to
maintain pressure
above bubblepoint.
Pumping 60% oil
2880
3600
Stop pumpout
44,000 cm3
Start sample
Throttling
Seal sample
January 1994
23
4
Visible
Near infrared
Crude B
Optical density
3
Oil base
mud
filtrate
Crude A
Water
2
1
Condensate
Diesel
0
500
1000
1500
2000
Wavelength, nm
nOil and water spectra. As the wavelength of light increases from the visible to the
near infrared, the optical density of water changes from zero—transparent—to a high
absorbing peak at 1450 nanometers (nm) and an even higher peak at 2000 nm. The
spectra of various oils are also shown, some less optically dense (more transparent)
than others in the visible region. A distinctive absorption peak for all hydrocarbons
appears at 1700 nm. These peaks are used to distinguish oil from water.
Differentiating Fluids
The OFA module distinguishes water from
oil by differences in optical transmission of
light at visible and near infrared wavelengths. The relative intensity of transmitted
light—transmittance, defined as the ratio of
transmitted light energy to incident light
energy—is measured at different wavelengths. Because transmittance of typical
formation fluids may vary greatly versus
wavelength, it is often convenient to represent optical properties on a logarithmic
scale and to use a quantity called optical
density.6 The higher the optical density, the
less light is transmitted. A plot of optical
density versus wavelength is called the
absorption spectrum (above ). Three phenomena are primarily responsible for the
characteristics of these absorption spectra:
molecular vibration absorption, electronic
absorption and scattering.
Water, as experienced in everyday life,
absorbs very little light in the visible region.
This continues at the shorter wavelengths in
the near infrared region until a resonance in
the molecular vibration of the oxygenhydrogen [O-H] bond causes a sudden
increase in absorption forming a peak near
1450 nanometers (nm). Another resonance
in the O-H bond causes a second, much
stronger, peak near 2000 nm. For oils,
molecular vibration absorption peaks at
1700 nm, caused by a resonance vibration
in the C-H bond. The uniqueness and separation of these peaks permit differentiation
of oil and water.
24
Color—the result of electronic absorption—provides one more parameter for liquid identification. Hydrocarbon condensates appear clear or light reddish-yellow,
while other crudes may be dark brown or
black; undyed diesel and fuel oils tend to be
light to dark brown. The color of oil is determined by the shorter wavelengths—blue
and green—being absorbed while the
longer wavelengths—yellow and red—are
allowed to pass. The shorter wavelengths
are absorbed by electrons in aromatics and
asphaltenes in oil causing a change in their
atomic energy state—as the concentration
of asphaltenes goes up, more light is
absorbed. Analysis of color allows differentiation between oil-base mud filtrate and
crudes. Adding a dye to drilling mud could
be used to distinguish filtrate water from
connate water.
If particles mix with fluids—as in drilling
mud—or if oil and water emulsify, then light
will be scattered. This causes additional
reduction in transmitted light. If the scattering contribution to optical density is large,
the water and oil peaks may be obscured
and difficult to interpret. In this case, the
fluid is said to be highly absorbing and is
usually interpreted as mud.
The transmission measurement is made
by directing light from a tungsten halogen
lamp to either of two paths. One path is
used for calibrating the sensor for minor system drifts before a measurement is taken.
The other goes to the flowline, which is
coupled to the light via small windows
made of sapphire, sapphire being more
resistant to abrasion than quartz. Either path
can be connected to a spectral distributor
where the light is separated into wavelengths—the intensity of each is measured.
The wavelengths are chosen to optimize the
determination of both the water/hydrocarbon ratio and the color of the fluid in the
flowline (below ).
Spectral transmission measurements also
permit a quantitative holdup analysis in oilwater systems.7 But complications arise
when gas is present. Scattering from the
interface between liquid and gas, such as by
a bubble, attenuates the transmission beam.
First, this can add a roughly constant offset
to the optical density curves. Second, the
presents of gas reduces the height of the
hydrocarbon peak, adversely affecting a
quantitative holdup analysis. In fact, the
hydrocarbon peak height is approximately
linearly related to the gas concentration, but
relying on this alone does not guarantee that
gas is present. A second sensor is therefore
used to detect gas and raise a warning flag.
Lamp
Measure
path
Source
path
Sapphire
windows
Formation
fluids
Flowline
Shutter
Spectral
distributor
Detectors
nOFA spectroscopy measurement system.
Light from a tungsten halogen lamp is
directed along either of two paths. One
path is used for downhole calibration,
while the other directs the light to the
flowline for measurement. Light passes
through the flowline fluid via sapphire
windows to a light distributor where photodiode detectors, each tuned to a different wavelength, measure the transmission intensity. Liquid analysis is made
from these measurements.
Oilfield Review
Detecting Gas
6. Optical density is defined as the logarithm of one
divided by transmittance. In other words, a transmittance of 100% is equal to an optical density of 0, a
transmittance of 10% is equal to an optical density of
1 and so on.
7. Water cut is the percentage volume of water produced from a formation over a period of time. Water
holdup is a snapshot of the percentage volume of
water occupying a pipe or flowline under dynamic
conditions. Because of different densities between
flowing fluids, there is often a difference in flow
velocity—the water holds up the oil. Water holdup
will be greater than water cut if the difference in
velocity of oil and water is greater than zero. If there is
no difference in velocity, then water holdup and water
cut will be the same.
8. Light is an electromagnetic wave that oscillates in a
plane perpendicular to its direction of travel. Polarized light is light whose oscillations are confined to
one plane only.
January 1994
Critical angle
Approximate band covered
by detector array
100
Air
Relative reflection intensity, %
Gas is detected by measuring reflected polarized light.8 The amount of light reflected at a
surface between two media depends on the
media, the angle of incidence and whether
the light is polarized. The reflection of all
light, polarized or not, is governed by the
critical angle. At angles of incidence greater
than the critical angle, all light is reflected
and none transmitted. At less than the critical
angle, some light is reflected and some is
transmitted. When light is P-polarized—that
is, polarized parallel to the plane of incidence—there is a particular angle smaller
than the critical angle, called the Brewster
angle, that allows 100% transmission. Since
values for the Brewster and critical angles
differ significantly between gases and liquids, measuring the relative intensity of the
reflected light over a range of angles permits
positive identification of gas (right ). Using
both angles is desirable to detect gas in the
presence of liquids.
The reflection measurement is made using
monochromatic infrared light emitted from
a light-emitting diode (bottom, right ). This is
polarized and passed through a cylindrical
lens, prism and sapphire window into the
flowline. An array of six detectors measures
the intensity of light reflected from the sapphire/fluid interface at discrete angles, from
just below the Brewster angle for air, to just
below the critical angle for water. Calibrations are carried out with air and then with
water in the flowline. A gas flag is currently
generated by a simple algorithm that uses
the shape and location of the measured
reflectivity curve between the 100-percentair and 100-percent-water curves. Reflection responds to the interface between two
materials, in contrast to transmission spectroscopy, which samples the bulk material.
Hence, the gas detector responds to free gas
at the surface of the sapphire window,
which may not necessarily represent the
Water
Oil
95
90
10
5
0
0
15
45
60
Angle of incidence
Less than
critical angle
Lens and polarizer
nRelative reflection
intensity of P-polarized light for air,
water and a typical oil. The relative
reflection intensity
is shown for varying angles of incidence for air, water
and oil. The reflection intensity
decreases to zero
for P-polarized
light at an angle
of incidence called
the Brewster angle.
As the angle of
incidence is
increased, the
reflection intensity
increases until total
internal reflection
occurs at the critical angle. Brewster
angles and critical
angles are different
for air, water and
oil. Measuring
reflection intensities
over a range of
angles provides the
basis for the gas
detection sensor.
Brewster angle
Sapphire prism
Detector
array
LED
Formation fluids
Flowline
nGas detector optics. Light from a light-emitting diode (LED) is
polarized and spread over a range of incident angles through a
sapphire window at the flowline. An array of detectors measures
the reflection intensity over angles from just below the Brewster
angle for air to just below the critical angle for water. Comparing
intensities with those obtained from master calibrations allows gas
detection flags to be raised on the log.
25
volume fraction of gas present in the flow.
However, liquid films on the sapphire window do not impede gas detection.
Distinguishing between single phases of
oil, water or gas in the flowline using the
OFA module is straightforward: the gas
detector shows either gas or liquid, while
the absorption spectroscopy peaks define
the liquid. If the flow is two or three phase,
a more complex analysis is required to
quantify volume fractions. This is possible
for liquid holdup as the absorption spectrometer measures optical densities across
the flow. However, the gas detector measures light reflected at the liquid sapphire
interface, which generally produces a larger
signal for greater gas fractions, but may not
be representative of gas holdup.
At present, water holdup is calculated
directly from the calibrated responses of the
detectors tuned to the two water peaks relative to those tuned to wavelengths at which
water has very little absorbance. Subtraction
from unity then gives hydrocarbon holdup.
In addition, the log presents an oil indicator
by shading the separation between the output of the detector tuned to the oil peak and
the output of the detector tuned to a wavelength between the oil peak and the 1450nm water peak. The magnitude of the separation gives an approximate measure of the
oil volume fraction in a gas-oil mixture.
When combined with the hydrocarbon
holdup estimate, this can yield a rough
appraisal of oil holdup. Since scattering
reduces light transmission, a shift from the
baseline of the optical density curves shows
the magnitude of scattering. Independently,
the gas detector flag indicates the presence
of gas. The recording also presents optical
densities measured by each transmission
detector. These are tracked in time, and give
additional indications of changes in flowline
fluid composition. For a more formal
approach to future interpretation development, see “Effective Flow Stream Model,”
(below ).
Examples of Sampling Using
the OFA Module
In a field test in a naturally fractured formation, the dual-packer module was used to
provide a good seal and the OFA module
was used to monitor the flowline fluid composition during a pretest and subsequent
sampling operation. 9 A display of each
channel from the OFA spectroscopy measurement system shows the optical density
measurement recorded throughout (next
page ). Channels 1 to 6 sample the spectrum
below the first water peak and respond to
color. Channels 6 to 10—channel 6 is
repeated—are the water/oil channels and
respond to changes in the region of high
9. Smits AR et al, reference 4.
Effective Flow Stream Model
Flow regime
Flow direction
Model
Light
Oil
Water
Oil
Water
nTransforming flowline contents to effective flow stream (EFS) model. The two-phase flow stream cross sec-
tion (left) is grouped into different flow regimes and simplified (right) into a model consisting of a number of
optical components in parallel and series with the light. The calculation of oil and water holdup and estimations
of fluid coloration and light scattering involves the solution of 10—one for each wavelength—simultaneous
equations given by this model.
A somewhat more formal approach to interpreting
The EFS model provides a method for reducing the
as occurs from particulates, emulsions and gas-
complex flow regimes along the flowline through
dynamic flow to a static optical equivalent (above).
liquid interfaces, also contributes to attenuation by
the OFA absorption sensor uses the Effective Flow
The transition from flow stream to static model is
removing photons from the optical beam path.
Stream (EFS) model. It employs a set of transmis-
made by grouping slug flow, emulsion or bubble
This is treated for both mixed and segregated
sion equations, one for each of the detectors. The
flow, and layered flow, so as to segregate the
phases as a wavelength-independent equivalent
unknowns correspond to oil and water holdups,
transmissions accordingly. The EFS model reduces
absorption in series with that of the flow compo-
degree of oil coloration and amount of scattering.
this to a simple partitioning of series and parallel
nents. The EFS model is also the basis for the
transmissions. This model represents the mea-
ongoing development of additional, improved
sured transmission as just the time average of
interpretation algorithms.
transmissions through oil, through water, and
through oil and water in series. Scattering, such
26
Oilfield Review
Pumpout Motor
Time, sec
Oil Indicator
SC 1
Valve
Pos’n
Highly Absorbing
Fluid
Pumped Volume
0
cm3
Water
Fraction
20,000
Hydrocarbon
Fraction
Pressure
0
psia
5000
Gas
1
0
0
Optical Density
Color
Channels
1
Comments
Water,
Oil
Channels
150
Inflate packer
Packer
pretest
Start
pumpout
1050
Pumping
filtrate
1950
Pumping oil
Stop
pumpout
2850
Start sample
Throttling
Change
throttle
3750
January 1994
nFormation sampling with dualpacker and
pumpout modules.
The top of the log
(0 to 350 sec)
shows the
pumpout module
being used to
inflate the packers
of the dual-packer
module—the OFA
reading shows
mud. During the
packer pretest (400
to 750 sec) the OFA
reading again
shows mud. Fluid
is then pumped out
from between the
packers changing
from mud to filtrate
(showing as
water), and finally,
at 2200 sec, to oil.
Pumpout is
stopped at 2550
sec and the sample
chamber opened.
During sampling,
throttling controls
the flowing pressure to ensure gas
stays in solution.
The 10 optical density channels are
displayed to give a
visual presentation
of density changes
throughout the test.
Channels 1 to 6
sample the fluid
spectrum below
the water peak at
1450 nm and give
an indication of
changes in color.
Channels 6 to 10
are the oil/water
channels responding to changes
above 1450 nm.
Seal sample
27
10. Smits AR et al, reference 4.
28
Time, sec
absorption peaks. The character of the spectrum at any time can be visualized by
sweeping the eye from left to right across
the log and noting changes in optical density. Hydrocarbon and water holdup curves
are shown in the adjacent track.
In this example, the absence of a gas flag
suggests that the hydrocarbon is all oil. Confirmation of this is visible on the oil indicator, which correlates well with the estimated
hydrocarbon fraction and with optical density in the color channels. An initial flow of
mud is visible on the optical density curves.
These produce the highly absorbing fluid
indicator that appears at the beginning of
the log. The highly absorbing fluid flag
appears whenever all of the detectors sense
essentially no light.
The OFA response to gas is shown in
another field test where alternating slugs of
water and gas occur (right ).10 The optical
density track shows no absorption in the
color channels, suggesting absence of oil,
and increased density in channels that
respond to the water absorption peaks.
Water- and hydrocarbon-fraction curves
step between 0 and 1 as slugs pass, and the
gas flag responds similarly. The oil indicator
confirms that the hydrocarbon is gas, and
not a light oil that is transparent in the visible region—no shading can be seen. The
transmission differences between gas and
water slugs cause oscillations in the optical
density curves—and, hence, the oil indicator curves—and not because of changes in
scattering. The very slight time shift between
Oil Indicator
Pressure
0
psia
5000
Gas
1
Optical Density
Hydrocarbon
Fraction
Water
Fraction
0
0
1
Color
Channels
Water,
Oil
Channels
5520
5580
nSection of log display during acquisition of a gas sample. The OFA spectroscopy measurement alternates between water and hydrocarbon. The color channels show transparent fluid, whereas the water/hydrocarbon channels oscillate. The gas detector
shows oscillations between liquid and gas. The conclusion is that alternating slugs of
gas and water are moving along the flowline.
the optical density and gas-indicator curves
results from the small flowline distance
between the two sensors.
Comparing measurements by the OFA
module with surface observations on the
chamber contents must be done with
care—gas can come out of solution and liquids can vaporize. Preserving downhole
temperature and pressure is necessary for
valid comparisons since even returning
them to their downhole values may not
guarantee recombination of phases to their
original condition. So far, OFA outputs have
mostly been consistent with other knowledge about fluid production in individual
wells. Several field tests have shown good
agreement between OFA measurements and
chamber analyses for oil and water, even
though the OFA module measures holdup
and the chamber contents represent timeintegrated cuts. Other tests show quantitative disagreements that could be caused by
several factors such as not flowing through
the OFA module during sampling or sampling at substantially different flow rates to
those during pumpout.
Further developments in OFA measurement and interpretation are in progress and
new applications can be envisioned: aiding
interpretation of drawdown pressure tests,
providing new information on formation
invasion and making quantitative estimates
of bubblepoint under downhole conditions.
—JT, AM
Oilfield Review