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The Why’s, Do’s and Don’ts of
Multi-Phase Flow Measurement
Traceability from Process to Laboratory
(Whitepaper)
WHI106PE1111
VATno. NL
8060.61.017.B01
I www.hint.nl
De Netelhorst 4
8051 KE Hattem
The Netherlands
T +31 38 4432300
F +31 38 4432301
E [email protected]
VATno. NL
8060.61.017.B01
I www.hint.nl
Table of Contents
About the author .................................................................................................................................................. 2
Abbreviations ........................................................................................................................................................ 2
Measuring Multi-Phase Flows .............................................................................................................................. 3
Benefits Multi-Phase Flow Meter ....................................................................................................................... 3
Multi-Phase Flow conditions and regimes ........................................................................................................ 4
The measurement process .................................................................................................................................. 5
The meter .............................................................................................................................................................. 6
How to select the appropriate MPFM ................................................................................................................ 7
About the author
Dr. Hans R.E. van Maanen
Metering Specialist
He likes to bring his specific knowledge, both in width as in depth, into
teams, is perseverant and tenacious. ‘Has good analytic powers and he can
“see outside the box”’ (quotes from several appraisals in Shell).
Experience
Hans van Maanen worked 41 years for Shell. Hans is specialised in Multi-phase flow measurement
with the main focus on “wet gas” and produced water because of hydrate formation. This includes
both research and development in this area as well as advice / problem solving for operating units
worldwide.
He gave much attention to the complications with phase changes between gas and liquid because of
changes in pressure and temperature, and the commingling of the fluids from different reservoirs.
Correction by means of PVT simulation and e.g. API tables is required for the correct split of the
revenues.
Since 2010 Hans van Maanen is working for Hint as a Metering Specialist.
Abbreviations
API
CapEx
CPP
e.g.
GLR
GOR
GVF
LVF
MPFM
N.B.
PVT
WOR
American Petroleum Institute
Capital Expenditure
Central Processing Plant
exempli gratia (Latin for “for example”)
Gas/Liquid Ratio
Gas/Oil Ratio
Gas Volume Fraction
Liquid Volume Fraction
Multi-Phase Flow Meter
Nota Bene (Latin for “note well”)
Pressure Volume Temperature
Water/Oil Ratio
The Why’s, Do’s and Don’ts of Multi-Phase Flow Measurement
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Measuring Multi-Phase Flows
Virtually all flows from oil and gas wells are “multi-phase”, meaning that a mixture of different
phases, usually gas, oil and water, are flowing out of the well.
For several reasons, it is important to know how much of the different phases are flowing out of a
well:
• production planning
• reservoir management
• maximizing the ultimate recovery of a field
• revenue allocation
All these are linked with the cash flow of the owner of the field.
Traditionally, the well production is measured using a “test-separator”, which basically is a very
large vessel where the three phases are separated by gravity and each phase is subsequently
measured with a single phase flow meter, after which the phases are commingled again. First of all,
these test-separators are costly themselves, are heavy, which is a large disadvantage off-shore and
require additional infrastructure like manifolds and test-lines. Secondly, they only provide data
about a well during the test and as a test-separator is often used for many wells (20 -40), there is
no direct information about the well behaviour during the intervals in between two successive tests.
In this way, e.g. water break-through cannot be detected at the moment it happens, but only at the
next test. An additional problem is the limited rangeability of the test-separator and its meters: at
too high flow rates, the separation is incomplete (liquid carry-over in the gas leg, gas carry-under in
de liquid leg, oil-in-water and water-in-oil), at the low flow rates, it is questionable whether the
system has reached equilibrium during the limited time of the test and the single-phase meters
loose accuracy.
The use of a test-separator enforces a topology of the field with individual production lines from
each well to the Central Processing Plant (CPP) and test lines, including many manifolds and valves.
As a result, the capital expenditure (CapEx) is high and the maintenance costs also. This situation
can be improved significantly by the use of multi-phase flow meters (MPFM's).
Benefits Multi-Phase Flow Meter
First of all, the infrastructure can become much simpler: as an MPFM is mounted on each well, the
need for test-lines disappears as well as the need for individual production lines to the CPP, which
significantly reduces the CapEx. The use of trunk-lines, in which each well dumps its production, is
feasible, reducing the CapEx even further. And last-but-not-least, the elimination of the testseparator itself with the additional manifolds and valves saves a lot of CapEx. So the costs of a field
development using MPFM's is significantly lower, even on-shore, than with a test-separator. Offshore, the savings are even larger as the support structure for the test-separator is no longer
needed. As a bonus, the flow information of each well is available continuously, so acting when a
problem occurs is simple, thus improving reservoir management and simplifying production
management.
When production needs to be changed, the availability of direct flow measurement data is
attractive as it also simplifies fulfilling the contractual agreed production volume and thus
avoidance of fines.
Many reservoirs lie in complex geological structures and if the production is not done using a
prescribed profile, the production can be hampered and the ultimate recovery lowered. This can
reduce the revenues and the returns on the employed capital significantly (for those who think this
is not really worthwhile: calculate the loss when the Ultimate Recovery (UR) is 1% less of a
mediocre reservoir).
Before a decision is made on the infrastructure and the topology of the field development, it is
essential to include an estimation of the required accuracies for the different phases. An accuracy
of 10%, which is frequently considered acceptable for well flow measurement, is not always a good
choice. When e.g. the well under scrutiny is a gas well, the value of the gas might be the most
The Why’s, Do’s and Don’ts of Multi-Phase Flow Measurement
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important, whereas the HC liquid, produced with the gas is small. Demanding a 10% uncertainty for
the liquid might be overstretched as this is -in this specific case- less than 1% of the total mass flow
rate. On the other hand, for e.g. hydrate inhibition, the water mass flow rate measurement might
require a high accuracy. So there are many aspects involved which require expert input.
Multi-Phase Flow conditions and regimes
The use of MPFM's, however, requires a different way of working and it requires knowledge of the
field development team. The main reasons are:
• Multi-phase flow is not so easy to understand
• The well changes over lifetime, in pressure, flow rate, GOR, GLR and WOR
In a multi-phase flow, the phases (gas, oil and water) move with different velocities (often called
slip or hold-up) and the velocity differences depend on many parameters like densities, viscosities,
flow line inclination GLR and the like. And as these parameters change over the life of the well, this
needs to be taken into account. To help the design, a number of different multi-phase flow
conditions have been introduced:
• Wet-gas (actual GVF > 90%)
• High GVF (80% < actual GVF < 95%)
• Multi-phase (actual GVF < 80%)
N.B. All these conditions are multi-phase
N.B. As the definitions are not cast in concrete, the boundaries are sometimes overlapping.
Next to this, a number of different flow regimes are specified.
For horizontal flows (see figure 1):
• Stratified
• Stratified-wavy
• Stratified entrained
• Annular-mist
• Slug flow
• Bubbly flow
• Plug flow
For vertical flows (see figure 2):
• Annular-mist
• Slug flow
• Churn flow
• Bubbly flow
Figure 1 (Flow regimes in horizontal flow)
The Why’s, Do’s and Don’ts of Multi-Phase Flow Measurement
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Figure 2 (Flow regimes in vertical flow)
The measurement process
A multi-phase flow meter has the task to measure the three phases under all the mentioned
conditions and flow regimes, so this is not an easy task. Therefore, the first developments focused
on meters which were suited for specific flow conditions. The separation between “wet-gas” and
“multi-phase” flow meters has been around for a long time. Gradually, “full-range” MPFM's are
becoming available, in which the different flow conditions are handled by specific data-processing
software, tailor made for the different flow conditions.
To cope with these problems, the physics, which govern the measurement process, need to be
analysed and understood. The introduction of several specific and dimensionless numbers is
essential in this respect, the most important ones are:
v sg =
Qg
π
4
D2
in which:
vsg
= Superficial gas velocity
Qg
= Volumetric gas flow rate
D
= Internal pipe diameter
vsl
= Superficial liquid velocity
Ql
= Volumetric liquid flow rate
Frg
= Gas Froude number
ρg
= Gas density
g
= Gravitational acceleration
ρl
= Liquid density
Frl
= Liquid Froude number
LM = Lockhart-Martinelli parameter
X
= Lockhart-Martinelli parameter
Q
v sl = π l 2
4 D
Frg =
ρg v sg2
gD( ρl − ρ g )
Frl =
ρl v sl2
gD( ρl − ρ g )
LM = X =
Frl
Ql
=
Frg Qg
m/s
m3/s
m
m/s
m3/s
kg/m3
m/s2
kg/m3
ρl
ρg
The Why’s, Do’s and Don’ts of Multi-Phase Flow Measurement
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To illustrate the complexity of multi-phase flow measurement, the effect of liquid on a Venturi flow
meter is presented in figure 3 (from H. de Leeuw, "Liquid correction of Venturi Meter Readings in Wet
Gas Flow", Proceedings of the North Sea Flow Measurement Workshop, October 1997, Kristiansand,
Norway) .
P=15 bar
1.8
1.7
Venturi overreading (Qtp/Qg)
P=30 bar
1.6
P=45 bar
1.5
P=90 bar
1.4
1.3
limit
1.2
1.1
1
0
0.05
0.1
0.15
0.2
0.25
0.3
0.35
Lockhart-Martinelli parameter (X)
Figure 3 (The influence of liquid reflects in the measured differential pressure of a Venturi, but as the
graphs show, there is also a dependence on the gas density.)
The interpretation of multi-phase flow measurements is not straightforward. The distribution of the
fluids over the cross section of the pipe and the velocities of the phases, which are also dependent
on the position, complicate the interpretation of these primary measurements significantly. This
requires deep insight into the physics of multi-phase flows in meters and modelling of the flow
phenomena.
The meter
An MPFM usually consists of a robust “primary” meter, often a Venturi. As unprocessed fluids pass
through the meter, the familiar problems of production, like erosion, corrosion, wax and scale
deposition can occur. A robust meter like a Venturi is therefore a good choice. But as we need to
determine three flow rates (gas, oil, water), a single “primary” measurement is not sufficient, so
additional information needs to be gathered. Examples are:
• Measurement of the total pressure loss (ratio) of the Venturi
• Conductivity of the liquid
• Permittivity of the mist
• Gamma ray absorption (one or two energy levels)
• Velocity measurement using cross-correlation
There are several manufacturers of MPFM's, an example is shown in figure 4, so a selection
beforehand is necessary. Not everybody is an expert in this specialized field, so care has to be taken
by the interpretation of the specification of the manufacturers. As there is no agreed way to specify
the performance, the comparison is not always easy. Also, the requirements can be different from
The Why’s, Do’s and Don’ts of Multi-Phase Flow Measurement
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De Netelhorst 4
8051 KE Hattem
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T +31 38 4432300
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case to case. It is -in generalrecommended to obtain
independent advice from experts
in the field of MPFM's as the
information from the
manufacturer might be biased,
whereas the expertise within the
oil company might be insufficient
to judge the quality of the
information, provided by the
manufacturer.
Maintenance and validation of
MPFM’s requires special
consideration.
MPFM’s can be complex error
prone instrument systems. Simple
and robust meters should be
preferred, as the measured
products can easily disable
complex sensor systems. For the
simpler and more robust meters
the added value is provided by
interpretation of the raw
measurement data, rather than
direct measurement.
Furthermore the maintenance and
repairs of MPFM’s have to happen
in hostile environments and places
that are difficult and expensive to
access.
How to select the
appropriate MPFM
MPFM’s are no standard price book
items, their selection and
configuration requires a solid
amount of homework. The knowhow for good selection has to
come from several disciplines,
ranging from reservoir geology,
physics, chemistry, metrology,
instrumentation, to operation and
maintenance practices. Shortcuts
Figure 4 (Example of a multi-phase flow meter)
during the definition phase can
have very costly consequences if
the equipment does not perform in the field.
Hint can provide the expertise to find the best solution for multi-phase flow measurement also in
your situation. Please feel free to contact Hint ([email protected]) or the author by e-mail
([email protected]) for starting a personal dialog on the subject of MPFM’s.
The Why’s, Do’s and Don’ts of Multi-Phase Flow Measurement
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