Download Multiphase Fluid Samples: A Critical Piece of the Puzzle

Multiphase Fluid Samples: A Critical
Piece of the Puzzle
A new multiphase sampling tool allows operators to capture representative fluids
without separation equipment. The ability to accurately analyze fluid composition in
real time creates opportunities for them to replace conventional testing equipment
with more-efficient and often more-accurate multiphase flowmeters.
Poor well test data can be as bad as no well test
data, especially for those charged with field
development planning or production management. Applying unreliable results to long-term
planning—particularly when modeling large or
complex reservoirs—inevitably leads to less-
than-optimal drainage strategies. Measurements
are often distorted by such common events as
wells flowing at rates beyond the test separator
capacity or well fluids arriving at surface in the
form of foams, oil-water emulsions, heavy oils or
condensate-laden wet gas.
Vitaliy Afanasyev
Noyabrsk, Russia
Paul Guieze
Alejandro Scheffler
Clamart, France
Bruno Pinguet
Maturin, Venezuela
Bertrand Theuveny
Moscow, Russia
Oilfield Review Summer 2009: 21, no. 2.
Copyright © 2009 Schlumberger.
For help in preparation of this article, thanks to Mahdi
Baklouti, Olivier Loicq, Federico Ortiz Lopez and Gerald
Smith, Clamart; and David Harrison, Houston.
PhaseSampler, PhaseTester, PhaseWatcher, PVT Express
and Quicksilver Probe are marks of Schlumberger.
1. Mullins OC, Elshahawi H, Flannery M, O’Keefe M
and Vanuffellen S: “The Impact of Reservoir Fluid
Compositional Variation and Valid Sample Acquisition on
Flow Assurance Evaluation,” paper OTC 20204, presented
at the Offshore Technology Conference, Houston,
May 4–7, 2009.
30
Oilfield Review
> Smaller and lighter. The traditional test separator (left) has a footprint of 5.68 by 2.24 m, is 2.45 m high [18.7 by 7.4 by 8.0 ft] and weighs
15,000 kg [33,000 lbm]. By comparison, the PhaseTester MPFM (right) measures 1.50 by 1.65 m, is 1.77 m high [4.92 by 5.41 by 5.81 ft] and weighs
1,700 kg [3,750 lbm].
Efficient production of formation fluids
requires accurate predictions about how temperature and pressure changes that always
accompany reservoir depletion affect the constituent fluid and formation properties. In remote
areas and on deepwater platforms, lack of infrastructure, space and weight restrictions and
transport logistics can make traditional testing
and metering equipment impractical. Fluids produced in deep water—cooled by their trip to the
surface through thousands of feet of pipe in nearfreezing water—sometimes cannot be heated to
a temperature sufficient to accomplish separation.
At the same time that the industry is struggling with those challenges, an increasing portion
of operators’ portfolios is made up of the type of
reserves historically avoided because they are
difficult to produce economically. These include
heavy oils, wet gas and other unconventional
fluids that defy phase separation.
In installations where weight and space must
be taken into consideration or where complex
fluids make phase separation difficult, multiphase flowmeters (MPFMs) are quickly gaining
acceptance as an alternative to traditional separators and test units. They are more convenient
and have a smaller footprint than traditional
separator-based meters and test units, and they
can be used to measure flow rates without prior
separation of fluids into phases (above).
Additionally, the fact that MPFMs are flowthrough devices means they are safer to operate
and do not generate disposable fluids. In contrast, separators must contain fluids under
pressure and elevated temperatures for some
period of time to effect separation.
Summer 2009
Until recently, however, the effectiveness of
MPFMs was hobbled by a significant drawback:
Confidence in the accuracy of flow rates
calculated without separation was limited by
the absence of representative fluid samples for
validation. Such samples are critical for determining in situ volumetric ratios and dry
gas properties used to minimize uncertainties in
flow measurements.
Another method of downhole sampling uses
wireline tools to capture the fluid and keep it in a
chamber at in situ conditions while it is brought
to the surface and then transported to a laboratory for analysis. Because this process includes
the risk and expense of a well intervention, many
operators prefer to take samples at a separator
on the surface.
The accuracy of downhole sample analysis is
also hampered by the need to acquire samples in
a manner that ensures they are indeed representative of the entire reservoir. But reservoir fluid
properties are variable, and laboratory evaluation must be understood in the context of the
spatial distribution of complex fluids within the
reservoir. Unrecognized formation compartmentalization increases the uncertainty of downhole
sampling. Reservoirs with multiple compartments can yield very different fluids within one
production zone and affect overall recovery.1
To address these issues, Schlumberger has
developed the PhaseSampler fluid sampling and
analysis system to be used in conjunction with a
PhaseTester portable MPFM or the permanently
installed PhaseWatcher MPFM. The sampling
tool is small enough to be fitted to the MPFM and
is easy to use (below). Laboratory tests using this
combination of services to calculate flow rates
and properties of conventional fluids yielded
> Simple attachment. The PhaseSampler multiphase sampling device (inset)
fits on the sampling port of the PhaseTester or PhaseWatcher MPFM.
Compact and easily attached, it requires no additional external power.
31
Flow
computer
Nuclear
detector
Nuclear
source
Venturi
Pressure
transmitter
Differentialpressure
transmitter
Flow
> Multiphase metering technique. PhaseTester MPFM technology is based on
measuring mass flow rate in the venturi spool using differential-pressure
sensors—a well-established method for flow rate metering in a single-phase
flow regime. A barium source emits gamma rays whose attenuation is
measured at two different energy levels. Measuring this attenuation in
multiphase media allows calculation of the density of the fluid and the mass/
volume fractions of the oil, water and gas. The combination of these
techniques with mathematical models provides information about the oil,
water and gas production. Engineers use the well test data to continually
diagnose production anomalies, quickly resolve problems and efficiently
produce wells. This technology can also capture flow rate measurement data
during cleanup.
This article examines the multiphase sampling
answers that are as accurate as those achieved by
tool
recently developed by Schlumberger and how
traditional methods.
Laboratory results have also proved that the it complements multiphase meters by enabling
use of MPFMs to test wells flowing heavy oil and capture of fluid samples without traditional sepawet gas delivers a more accurate picture of the rators. A case history from Siberia illustrates how
transient evolution of flow, volumes and rates flow rates can be improved using multiphase samthan is possible with traditional separators.2 pling and meters to test remote gas-condensate
Phase separation can rarely be achieved with wells. Another from Algeria demonstrates the
the efficiency required to deliver truly accurate accuracy of results achieved using the new
Rick_Fig03_2
sampling system to determine fluid properties.
flow calculations.
Determination of fluid properties, calculation
of flow rates and prediction of fluid behavior are Shrinking the Margin of Error
inseparable elements in developing reservoir MPFM technology is based on differentialdrainage strategies. Accurate determination of pressure measurement in a venturi spool—a
each becomes more critical with increasing fluid well-known method for single-phase flow meaand reservoir complexity. That is because the test surement that can be adapted for multiphase
results that once were considered not much more flow by adding a nuclear component to measure
than a common tool for decisions on whether to total mass flow rate and the holdups, or fractions,
complete a well have today become an indispens- of gas, oil and water (above).3 The resulting well
able data source for modeling and development test data are used to diagnose production anomaplanning. Production data from inline MPFMs lies continuously rather than periodically as must
are used to forecast the onset of problems as be done using separators. Also, data can be gathwells age and the composition of fluids changes ered during well cleanup—which increases
with temperature and pressure variations.
understanding of possible flow assurance problems, offers better well-performance assessment
and reduces test times. This is an impossibility
32
using traditional separators that must remain off
line until the well has returned drilling fluids or
other contaminants introduced into the formation during drilling and completion.
Immediate economic benefits of using MPFMs
for well testing include a reduced footprint. Also,
because little or no stabilization time is required,
it is possible to test more wells per unit of time.
These are especially attractive characteristics in
remote and deepwater locations where conserving
time and space is essential to project economics.
As a production-monitoring tool, MPFMs
exhibit excellent response to fluctuating flow;
require little or no stabilization time; and are
not affected by complex flow regimes such as
slugs, foams or emulsions. Because their operation is insensitive to changes in flow rate, phase
holdup or pressure regime, they require no process control. These capabilities give operators a
means to recognize such time-dependent events
as a change in flow regime or the onset of
hydrate formation. In turn, wellsite engineers
are able to adjust well treatment programs, flow
rates or other parameters before they impact
production efficiency.
MPFM devices measure flow rates at line
conditions. As a consequence, engineers must
turn to PVT calculations to convert these results
to the standard conditions used to compute
oil, water and gas flow rates. Three sets of PVT
data are required to calculate flow rates at standard conditions: densities, volumetric conversion
factors (from line to standard conditions) and
solution ratios. The liquid viscosity at line conditions must also be considered when heavy oil is
one of the phases.
These data are obtained through analyses of
samples collected at the surface or—when
feasible—acquired downhole with a wireline
tool, such as the Quicksilver Probe sampler.4 In a
multiphase environment, samples may be collected at the surface in two ways. The first is to
capture a known volume of a representative mix
of each phase from a traditional three-phase
separator. The second approach is to collect a set
of representative phase samples (oil, water and
gas) at line conditions and use independent measurements of each of the phase fractions in the
commingled flow to reconstruct the whole fluid.5
Separator Sampling
The validity of flow rates calculated from samples
taken at a separator is questionable because a
correct analysis depends on thermodynamic
equilibrium, in which both liquid and gas are at
the same pressure and temperature and in equilibrium with each other.
Oilfield Review
While discussions continue as to when
and at what point in the separation process
true equilibrium is reached, experts widely
acknowledge that such a condition is reached a
few feet after the fluid passes a choke, a change
in pipe size or other pressure loss–generating
flowline assembly. As a consequence, the
temperature and pressure of the phases within a
sample taken from a flowline are often not
at equilibrium.6 Additionally, it is impossible to
take high-pressure samples and, when one phase
is dominant, significant carry-over or carry-under
can occur and distort flow measurements.7
Once samples of each phase are collected,
there are several options for generating fluid properties. These include the use of black oil models
(BOMs) to estimate fluid properties from stocktank measurements; wellsite measurements;
equation-of-state (EOS) calculations using PVT
data generated during field exploration and
appraisal stages; or a full PVT laboratory analysis.
Black oil models are based on statistical functions that assume reservoir fluid consists of three
phases—oil, water and gas. Pressure, temperature and density are inputs and fluid composition
is included in the statistical measurement from
which the correlations are derived. EOS models
incorporate more fluid properties than BOMs and
are more scientifically defined, but they are only
as accurate as the PVT data analysis. These models are ineffective when PVT data are no longer
representative of the fluids because they have
changed in response to pressure and temperature variations. The response when such
conditions are recognized is to approximate some
of the necessary data, raising the level of uncertainty to that of the BOM.
To ensure accuracy in wellsite measurements
they must be acquired by experts. PVT laboratory
analysis can be time-consuming, though this may
not be an issue if accuracy is more important
than lost production time. Calculations are
derived from correlations that may limit accuracy
in certain fluids and that are particularly impractical for use in heavy oils and gas condensates.
Line Sampling
Collecting representative phase samples at line
conditions reduces the uncertainties introduced
by pressure, temperature and effluent variations.
In some cases, however, the complexity of
the multiphase flow regime makes it impossible
to sample a single phase at a time. To overcome
this challenge, researchers developed the
PhaseSampler system, designed for sampling
from areas within the flow stream where one
phase is dominant and the oil, gas and water are
Summer 2009
at equilibrium at line conditions. The system
hardware includes
•a three-probe sampler that fits into the flow­
meter port
•an optical phase detector to sense the type of
fluid entering or leaving the sample chamber
•a kit that allows direct measurement at the
wellsite of key fluid property inputs at line and
standard conditions for any type MPFM
•dedicated data-acquisition software that
receives the measured fluid properties as an
alternative to the correlation available with
standard multiphase meters.
Through the sampling trap, the probes are
placed in the flowline’s multiphase stream so
that the venturi is in front of the probes. This
positioning ensures the sample is well mixed and
not affected by fluid slugs or similar flow anomalies and is therefore representative of the flow
being measured by the venturi. Two of the probes
face upstream to capture mostly liquids; one is
placed at the bottom of the pipe, one at the top.
The third probe is positioned in the middle of the
flow path, facing downstream, and captures a
sample that is predominantly gas (below). The
captured fluid remains in a phase-segregating
Sampling
mostly liquid
Sampling
mostly gas
Sampling
mostly liquid
> Multiphase sampling. The location and orientation of the PhaseSampler
probes within the flow stream enable them to collect discrete, phaseconcentrated samples at line conditions. Two probes—one at the top and one
at the bottom of the flow path—face upstream and collect samples that are
predominantly liquid. The third probe is in the center of the pipe and faces
downstream. Numerous experiments have shown this alignment minimizes
the amount of liquid entering the tube and results in the capture of a sample
that is predominantly gas.
2. Afanasyev V, Theuveny B, Jayawardane S, Zhandin A,
Bastos V, Guieze P, Kulyatin O and Romashkin S:
“Sampling with Multiphase Flowmeter in Northern
Siberia—Condensate Field Experience and Sensitivities,”
paper SPE 115622, presented at the SPE Russian Oil &
Gas Technical Conference and Exhibition, Moscow,
October 28–30, 2008.
3. For more on multiphase flow measurement: Atkinson I,
Theuveny B, Berard M, Conort G, Groves J, Lowe T,
McDiarmid A, Mehdizadeh P, Perciot P, Pinguet B,
Smith G and Williamson KJ: “A New Horizon in
Multiphase Flow Measurement,” Oilfield Review 16,
no. 4 (Winter 2004/2005): 52–63.
4. For more on Quicksilver Probe technology: Akkurt R,
Bowcock M, Davies J, Del Campo C, Hill B, Joshi S,
Kundu D, Kumar S, O’Keefe M, Samir M, Tarvin J,
Weinheber P, Williams S and Zeybek M: “Focusing
on Downhole Fluid Sampling and Analysis,” Oilfield
Review 18, no. 4 (Winter 2006/2007): 4–19.
5. Afanasyev et al, reference 2.
6. Hollaender F, Zhang JJ, Pinguet B, Bastos V and
Delvaux E: “An Innovative Multiphase Sampling Solution
at the Well Site to Improve Multiphase Flow Measurements and Phase Behavior Characterization,” paper
IPTC 11573, presented at the International Petroleum
Technology Conference, Dubai, UAE, December 4–6, 2007.
7. Carry-over (liquids in the gas line) and carry-under (gas
in the liquids line) may result when a separator design is
ill-suited to the flow regime. Either can affect the
accuracy of multiphase flow rate measurements.
Rick_Fig04_1
33
sample chamber until a sufficient volume of the
targeted phase is collected (below).
The single-phase sample is then placed in a
flash apparatus for measurement of fluid properties or it is transferred into a sample bottle for
transport to a PVT laboratory for a recombination PVT study.8 The higher accuracy of the GOR
resulting from the improved characterization of
MPFM measurements enables a more-reliable
recombination and subsequent PVT analysis.
Optical phase detector
Optical phase detector
Oil
Oil
Water
Gas
Water
Gas
Optical phase detector
Optical phase detector
Oil
Oil
Water
Gas
Water
Gas
> Isolating one phase. Fluids captured by a probe (top, black arrow) enter a
sample chamber (middle left) where an optical phase detector distinguishes
between oil, water and gas. This dynamic fluid profiling continues throughout
the sampling process. The nontarget phases are displaced from the chamber
back into the flowline by a hydraulically activated piston (middle right, bottom
left—water flowline from bottom not shown) until only the phase of interest
remains (bottom right).
34
It is important to the recombination that
captured samples be validated. To that end,
Schlumberger developed a quality assurance/
quality check (QA/QC) concept that includes
sampling QA, rapid sampling QC, saturation-pressure determination and a cross-check with
separator or downhole sample when available. Of
these, the most powerful QC tool is PVT Express
onsite bubblepoint determination at sampling
temperature (next page).
Successful replication of the initial formation
fluid from recombination depends on a number of
variables including reservoir conditions, well
parameters and sampling procedures. For example, if the bottomhole flowing pressure is below
the initial dewpoint pressure, the formation fluid
will be diphasic; liquids deposited in the formation or in the near-wellbore region will not be
lifted. Consequently, recombination will reflect
only flowline fluids.
Recombination is accomplished by either
physical or mathematical means. Physical recombination requires single-phase samples of the
gas, oil or water and a gas/liquid ratio obtained
through MPFM measurements. Though no physical experiments are required for mathematical
recombination, additional information is needed.
These inputs include liquid density at recombination conditions, molecular weight of the liquid,
gas expansion factor and liquid/gas ratios.
Although the physical approach requires
more time and personnel investment and is more
subject to human error, it also offers significant
advantages over mathematical recombination.
These include
•tangible results in the form of monophasic
samples
•less uncertainty than from calculations
•opportunity for further analyses
•experimental saturation point
•in situ and stock-tank densities.
Recombination allows the development of a
compositional model for a monophasic fluid at
either formation or producing conditions.
Physical recombination enables this model to be
fine-tuned at experimental reference points. An
EOS is then used to simulate complex tests. The
resulting formation-fluid model can be used to
understand the drainage behavior of a field and
can be applied to its exploration, development,
production and forecasting.9
A Different Approach
Certain situations make it difficult to use traditional separators to gain insight into a field’s
drainage behavior. For instance, in fields with
Oilfield Review
Summer 2009
260
240
220
Pressure, bar
200
180
160
140
120
Bubblepoint
100
80
60
61
62
63
64
65
66
67
Volume, cm3
Diphasic
Monophasic
Optical signal (relative units)
200
150
Pressure, bar
high gas volume factors (GVFs), samples must be
truly representative or the PVT properties will
not have the accuracy necessary for correct rate
calculations.10 These samples may be hard to
capture by traditional means that rely on good
phase separation—a difficult task where such
fluids are concerned.
In 2007, after years of calculating flow rates
through periodic conventional testing, operator
Rospan International began investigating a multiphase well testing program to refine the geological
and dynamic models of its Urengoyskoe gascondensate field in northern Siberia. The decision
was based on the need for a more thorough understanding of drainage behavior because most
reservoirs had been produced at conditions below
the dewpoint. Despite depletion from earlier production, analysts determined the reservoirs would
support substantial future production.11
The field, discovered in 1966, is 80 km [50 mi]
south of the Arctic Circle. Capturing representative fluid samples from this location and then
transporting them for analyses at a laboratory
thousands of miles away would be impractical
and expensive. Also, conducting traditional well
tests and interpreting the data are made difficult
by complicated reservoir structures, relatively
high formation pressures and the physical and
chemical properties of the produced fluids.
Most production comes from the deep
Achimov Formation that lies more than 3,000 m
[9,800 ft] below the surface. It is characterized
by sandstones and siltstones with claystone
bands, irregularly distributed reservoirs and significant lithological facies variations. Net-pay
thickness ranges from 0 to 5 m [0 to 16 ft] for oil
zones and from 0 to 60 m [0 to 197 ft] for gas
intervals. Average porosity ranges from 15% to
18%. Oil saturation is 60% and gas saturation varies from 56% to 77%.12 Formation pressure ranges
from 530 to 660 bar [7,700 to 9,570 psi] and formation temperature from 17°C to 91°C [62°F to
196°F]. GVF is between 97% and 99.5%.
Rospan addressed the issues of great distances and complex reservoirs through the use of
a PhaseTester multiphase flowmeter and the
PhaseSampler device. The Schlumberger PVT
Express portable laboratory service was used to
deliver onsite compositional analysis of gas and
gas condensate without phase changes. These
samples were used for sample validation and
fluid-properties characterization.13
In one well, a PhaseSampler tool captured
fluid at the MPFM and a downhole single-phase
sampler captured a bottomhole fluid sample.
100
35.6, 98
50
0
–150
–50
50
150
250
350
450
Temperature, °C
PhaseSampler gas
PhaseSampler liquid
PhaseTester line
sampling conditions
> Quality assurance and check. Saturation pressure obtained at sampling
temperature can be used to validate samples from multiphase sampling
devices. The bubblepoint for the liquid sample (top) and the dewpoint for the
gas sample (not shown) should equal the sampling pressure. When a valid
sample is taken—at line conditions and in thermodynamic equilibrium—
phase envelopes for liquid and gas cross at the sampling point (bottom). For
quality purposes, the acceptable deviation of measured bubblepoint from
sampling is ±5%. Because the dewpoint is more difficult to detect, the allowed
deviation is ±20%. (adapted from Afanasyev et al, reference 2.)
  8.A flash apparatus facilitates observation of fluid
12.Gas saturation is the relative amount of gas in the pore
phase behavior at the moment sample pressure is
space of a formation, usually expressed as a percentage.
instantaneously released to atmospheric pressure.
13.Bastos V and Harrison D: “Innovative Test Equipment
  9.Afanasyev et al, reference 2.
Expedites Data Availability,” E&P 82, no. 2 (February
Rick_Fig05_1
2009): 64–65.
10. GVF is the gas volume at reservoir conditions divided by the
gas volume at standard conditions. This factor is used to
For more on PVT Express technology: Akkurt et al,
convert surface-measured volumes to reservoir conditions.
reference 4, and Betancourt S, Fujisawa G, Mullins OC,
An oil formation volume factor is used to convert
Carnegie A, Dong C, Kurkjian A, Eriksen KO, Haggag M,
surface-measured oil volumes to reservoir volumes.
Jaramillo AR and Terabayashi H: “Analyzing
Hydrocarbons in the Borehole,” Oilfield Review 15, no. 3
11.Romashkin S, Afanasyev V and Bastos V: “Multiphase
(Autumn 2003): 54–61.
Flowmeter and Sampling System Yield Real-Time
Wellsite Results,” World Oil 230, no. 5 (May 2009): 66–70.
35
450
105.5, 420
105.5, 394
400
350
Pressure, bar
300
250
PhaseSampler gas: 11.01
PhaseSampler liquid: 11.02
PhaseSampler sampling
conditions (6 mm)
BHS: 1.02
Bottomhole sampling SRS
Measured dewpoint
Mathematically
recombined
PhaseSampler samples
200
150
100
10.5, 83
50
0
–150
–50
50
150
250
350
450
Temperature, °C
> Validation of surface samples using a bottomhole sample (BHS). This graph
superimposes BHS phase envelopes and mathematically recombined samples
acquired by a multiphase sampling device. Bottomhole and line conditions are
shown for reference. Envelopes of the multiphase samples cross at the
sampling point (green dot). The single-phase reservoir sample (SRS) was used
in an EOS to obtain its phase envelope. A best-fit characterization (blue)
moved the phase diagram closer to the measured dewpoint (orange triangle)
and to the mathematically recombined monophasic sample (red curve) that is
consistent with the BHS.
Since sampling pressure was higher than the
dewpoint, it was assumed the reservoir fluid was
originally monophasic. However, it split into two
phases when pressure decreased as it flowed to
the surface. The samples were studied and
recombined mathematically using a gas/liquid
ratio averaged over the sampling period.
When plotted, the phase envelopes of the captured multiphase sample and the bottomhole
sample crossed at the sampling point, indicating
the condensate and gas phases were in equilibrium as they passed through the meter (above).
The experiment, as demonstrated by the
resulting plots, confirmed several important
100
Black oil model
900
Rick_Fig06_1
80
850
70
800
60
750
50
700
40
650
30
600
20
Oil density at line conditions, kg/m3
Volume, sm3/sm3
90
950
PhaseSampler analysis
550
Solution gas
Oil volume
factor
Oil density
> Differences and potential error. The differences in the BOM and the
PhaseSampler analysis for solution gas, oil volume factor and oil density were
significant. Using the BOM would result in underestimated oil shrinkage and
overestimated oil density, which could lead to significant errors in the large
Berkine basin. (adapted from Bastos and Harrison, reference 13.)
36
points for the operator:
•Samples from a multiphase sampling device
are good initial material for recombination.
•A gas/liquid ratio from recombination can be
used to reconstruct monophasic flow.
•An EOS works better than experimental reference points.
•Multiphase sampling and testing are viable
tools in formation fluid simulation.
In a second study conducted in the field, a
sample from a new well was physically recombined using wellsite analytical equipment and
the PhaseSampler service. After a day of reconditioning the sample at reservoir conditions,
25 cm3 was transferred to a PVT cell for QC and
saturation-pressure determination. This experiment resulted in a dewpoint pressure of 376.8 bar
[5,463.6 psi], essentially matching an earlier EOS
prediction of 382 bar [5,539 psi] based on mathematical recombination.
This outcome confirmed the feasibility of
using physical recombination on samples captured by a multiphase sampling device. It also
showed that recombination is easier to accomplish with these samples than with those obtained
using conventional means placed downstream of
a separator. And finally, it demonstrated that
physical recombination used in conjunction with
bottomhole data provides essential information
about flow regimes.
As a consequence of these examples and
other work done over a period of six months, the
Schlumberger and Rospan International team
has developed a multiphase sampling and analysis program specifically for the Urengoyskoe
condensate field. The procedure involves using a
multiphase sampling device and an MPFM on
each well. When possible, the process includes
sending one sample collected at the largest
choke setting and one collected at the smallest
setting to a laboratory for testing. Each sample
pair is recombined mathematically and physical
recombination is provided for samples from new
wells. A botttomhole sample is captured in every
fifth well.
14.Basic sediment and water, or BS&W, refers to impurities
contained in produced oil and is reported as a
percentage of the fluid in samples captured at the
surface. Its measurement is described in ASTM
Standard Test D96-82.
15.Bastos and Harrison, reference 13.
16.Oyewole AA: “Testing Conventionally Untestable
High-Flow-Rate Wells with a Dual Energy Venturi
Flowmeter,” paper SPE 77406, presented at the SPE
Annual Technical Conference and Exhibition, San
Antonio, Texas, USA, September 29–October 2, 2002.
17.Theuveny B, Zinchenko IA and Shumakov Y: “Testing
Gas Condensate Wells in Northern Siberia with
Multiphase Flowmeters,” paper SPE 110873, presented
at the SPE Annual Technical Conference and Exhibition,
Anaheim, California, USA, November 11–14, 2007.
Oilfield Review
80
180
PhaseSampler analysis
Laboratory results
60
120
90
60
50
40
30
20
30
10
0
1
2
3
N2
4
Well number
40
CO2
H 2S
C1
80
PhaseSampler analysis
Laboratory results
35
25
20
15
10
5
C3
iC4 nC4
Free gases
iC5
N2
CO2
C1
C2
C3
iC4
nC4
iC5
nC5
C6
C7
C6
C7
80
70
60
60
50
50
40
40
30
30
20
20
10
0
nC5
PhaseSampler analysis
Laboratory results
70
Volume, sm3/sm3
30
C2
Gas density at line conditions, kg/m3
0
Weight, mol %
PhaseSampler analysis
Laboratory results
70
Weight, mol %
Solution gas, sm3/sm3
150
10
Gas volume factor
Gas density
Dissolved gases
> Confirmation. Though the laboratory ambient temperature was 77°F [25°C], and wellsite temperatures ranged from 104°F [40°C] to 122°F [50°C],
measurements of solution gas by both PhaseSampler analysis and the laboratory were in good agreement (top). The PhaseSampler and PVT compositional
analyses for the free gas (top right) and dissolved gas (bottom left) were also in close agreement, as were those for the GVF and the gas density (bottom
right). Free gas and dissolved gas are represented by two bars in each graph to indicate samples measured using two different types of gas
chromatographs.
Measuring Differences
Whereas the flow and fluid property measure­
ment challenge in the Urengoyskoe field was a
product of complex geology and remoteness, in
the Berkine basin of eastern Algeria, multiphase
sampling was put to the test in four wells
with fluid parameters that varied significantly.
GOR across the wells ranged from 1,000 to
18,000 ft3/bbl [176 to 3,200 m3/m3], API gravity
from 40 to 53, basic sediment and water from 0%
to 33% and water salinity from fresh to over­
saturated brine.14
Operators Sonatrach and Anadarko, who had
formed a partnership to manage oil fields in the
basin, sought to determine whether the
PhaseSampler technology could accurately measure
reservoir fluid properties at each wellsite. The
operators required a three-step validation process:
•PhaseSampler results would be compared to
BOM predictions.
•PhaseSampler and PVT measurements of GOR
and gas composition would be compared.
•Repeatability would be tested by comparing mul­
tiple flashes under identical flowing conditions.
The match between PhaseSampler and labora­
tory results across the varying zones was good for
Summer 2009
measurements of solution gas, compositional anal­
ysis of free and dissolved gas and determination
of gas volume and density (above). Multiphase
sampling measurement repeatability was con­
firmed by the performance of eight flashes each
for gas and oil.
However, differences between solution gas
volume, oil volume factor and oil density as calcu­
lated with the BOM were significant (previous
page, bottom). This confirmed experts’ early con­
cerns that the BOM would underestimate oil
shrinkage and overestimate oil density. Had
these erroneous figures been applied to the deci­
sion-making process on a reservoir the size of the
one tested in the Berkine basin, the impact could
have been considerable.15
The Critical Piece
Traditionally, the industry has tested well flow
rates and reservoir potential through the use of
separators that break multiphase well effluent
into its constituent phases before the measure­
ment of each phase. But there have always been
concerns about the quality of a separation pro­
cess that uses test vessels that rely on gravity and
pressure reduction. Even when results appear to
be accurate, the method has inherent flaws.
Among these are carry-over, carry-under and dis­
crete measurements that in complex regimes,
such as slugging water, may lead to mistaken con­
clusions about water cut if the readings were
taken at the wrong time.16
Additionally, the type of reserves the industry
is exploiting is changing. There is now increased
demand for advances such as high-resolution
measurements of gas/liquid ratios to determine
changes in fluid properties at choke crossings.
Operators are also seeking greater test repeat­
ability to confirm slowly evolving trends, lower
risks associated with conventional separators
that capture hydrocarbons under elevated pres­
sure and temperature, and high-quality data from
permanent monitoring installations.17
The success of the multiphase sampling
device promises to eliminate any further objec­
tion to the use of MPFMs in both testing and
production monitoring. Laboratory tests and
comparisons with traditional sampling methods
and analyses have proved its ability to collect
representative fluid samples for real-time compo­
sitional analysis, thus providing a critical piece to
the multiphase flowmeter puzzle. —RvF
37