the why’s, do’s and don’ts of multi-phase flow...

De Netelhorst 4 T +31 38 4432300 VATno. NL 8051 KE Hattem F +31 38 4432301 8060.61.017.B01 The Netherlands E [email protected] I www.hint.nl

The Why’s, Do’s and Don’ts of Multi-Phase Flow Measurement

Traceability from Process to Laboratory

(Whitepaper)

WHI106PE1111

The Why’s, Do’s and Don’ts of Multi-Phase Flow Measurement of 7

WHI106PE1111


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 American Petroleum Institute CapEx Capital Expenditure CPP Central Processing Plant e.g. exempli gratia (Latin for “for example”) GLR Gas/Liquid Ratio GOR Gas/Oil Ratio GVF Gas Volume Fraction LVF Liquid Volume Fraction MPFM Multi-Phase Flow Meter N.B. Nota Bene (Latin for “note well”) PVT Pressure Volume Temperature WOR Water/Oil Ratio


WHI106PE1111


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 test-separator 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. Off-shore, 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


WHI106PE1111


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)


WHI106PE1111


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:

vQ

Dsg

g= π4

2

vQ

Dsll= π

42

Frv

gDg

g sg

l g

=−

ρρ ρ

2

( )

Frv

gDll sl

l g

=−

ρρ ρ

2

( )

LM XFr

Fr

Q

Ql

g

l

g

l

g

= = =ρρ

in which: vsg = Superficial gas velocity m/s Qg = Volumetric gas flow rate m3/s D = Internal pipe diameter m vsl = Superficial liquid velocity m/s Ql = Volumetric liquid flow rate m3/s Frg = Gas Froude number

ρg = Gas density kg/m3 g = Gravitational acceleration m/s2

ρl = Liquid density kg/m3 Frl = Liquid Froude number LM = Lockhart-Martinelli parameter X = Lockhart-Martinelli parameter


WHI106PE1111


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) .

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

Lockhart-Martinelli parameter (X)

Ven

turi

ove

rrea

din

g (

Qtp

/Qg

)

1

1.1

1.2

1.3

1.4

1.5

1.6

1.7

1.8

0 0.05 0.1 0.15 0.2 0.25 0.3 0.35

limit

P=90 bar

P=45 bar

P=30 bar

P=15 bar

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.)


WHI106PE1111


Figure 4 (Example of a multi-phase flow meter)

case to case. It is -in general- recommended 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 know-how for good selection has to come from several disciplines, ranging from reservoir geology, physics, chemistry, metrology, instrumentation, to operation and maintenance practices. Shortcuts 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...

Documents