Production Logging Interpretation
Production Logging Fundamentals
Learning Objectives
By the end of this lesson, you will be able to:
Present the calibration principles of flowmeter tools
Present the principles involved in interpreting production loggingtool data
Illustrate the performance of cased hole logs in multi-phase flow
Review the application of cased hole logs in deviated wells
Part 1
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• Spinner-type velocimeter which records a continuous flowprofile versus depth.
• Sensitive to the velocity differential between the tool andthe surrounding fluid.
• Most effective for single phase flow conditions in wells withhigh production rates and/or small inner casing diameter.
Continuous Flowmeter
Flowmeter Calibration ‒ Spinner Reversal
• A change of direction in spinner rotation under downholeexternal flow conditions.
Spinner Reversal Phenomenon
Flowmeter Calibration ‒ Spinner Reversal
No Flow
IncreasingVelocity
Flu
id e
ntr
ies
Below the fluid entry level, the spinner
rotatesclockwise due totool movementin static fluid
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Flowmeter Calibration ‒ Spinner Reversal
The spinner stalls when
tool velocity isclose to fluid
velocity
Flu
id e
ntr
ies
No Flow
IncreasingVelocity
Flu
id e
ntr
ies
No Flow
IncreasingVelocity
Flowmeter Calibration ‒ Spinner Reversal
The spinner starts rotating
again, in theopposite direction, asfluid velocity exceeds
tool velocityCOPYRIGHT
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Flowmeter Response and Calibration
Courtesy: Schlumberger
Mechanical losses
Viscous and Mechanical Losses
Net Flow Line
Zero Flow Calibration Line
There is no practical higher limit to spinner velocitymeasurement
There is a minimal flow rate below which the tool willnot operate
• The spinner will not rotate, due to internal friction and fluidviscosity
Fluid viscosity has an effect on spinner speed• Low viscosity increases spinner speed• The downhole response curve of spinner speed versus fluid
velocity must be established
Flowmeter Response and Calibration
Courtesy: Schlumberger
Spinner ResponseIdeal Response
Mechanical losses
Viscous and Mechanical Losses
Net Flow Line
Zero Flow Calibration Line
Vt = Threshold VelocityCOPYRIG
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Flowmeter Calibration ‒ Sign Conventions
Vf > 0 Fluid Moving Up
Vf < 0 Fluid Moving Down
Vc > 0 Tool Running Down (Depth Increasing)
Vc < 0 Tool Running Up(Depth Decreasing)
Vc<0
SPIN<0Vf<0
Vc<0
|Vc|<|Vf|
SPIN>0Vf>0
Vc<0
|Vc|>|Vf|
SPIN<0Vf>0
Vc>0
SPIN>0Vf>0
Vc>0
|Vc|<|Vf|
SPIN<0Vf<0
Vc>0
|Vc|>|Vf|
SPIN>0Vf<0
Vc = Cable Speed (Tool Velocity)
Vf = Fluid Velocity
Log: Up /
Down
Cable Speed,
ft/min (m/min)
Spinner Rotation at Stations (rps)A B C D
Down 115 (35.1) 20.0 15.2 9.2 5.1
Down 82 (25.0) 18.7 13.5 7.5 3.5
Down 50 (15.2) 17.2 12.2 5.4 2.1
Up 32 (9.8) 13.2 8.2 1.9 -1.1
Up 80 (24.4) 11.5 6.2 -3.0
Up 110 (33.5) 9.9 4.8 -4.6
A
B
C
D
Flowmeter Logging (Log Up and Log Down)
50 ft/min
82 ft/min
115 ft/min
32 ft/min
80 ft/min
110 ft/min
No Flow
Full Flow (1829)
(1859)
(1890)
(1920)
(1951)
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Flowmeter Multipass Calibration Technique
=
Slope depends
only on spinner
geometry
Down
Threshold Velocity, Vt
Tool Velocity(ft/min)
Slope depends onlyon tool geometry
Zero Flow Line
(rps/ft/min)ΔRΔV
Slope m
ΔR
ΔV
Sp
inn
erR
esp
on
se(r
ps)
Fluid Velocity
Flowmeter Multipass Calibration Technique
Multiple Data Points
This plot is essential to identify possible issues at stations:
• Readings do not align, or• Slopes differ too much
Anomalies should be investigated while the tool is still downhole
Company representatives should be present and interpreting recordings in real time
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Turbulent Versus Laminar Flow
Dye injection
Laminar
Turbulent
Low Flow Rates
Higher Flow Rates
Turbulent Versus Laminar Flow
Spinner Response under various flow regimes
CORRECTION FACTOR
LaminarLaminar TurbulentTurbulent
APPARENT VELOCITY
AVERAGE VELOCITY
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Laminar Flow
Flowmeter centered in tubingand measuring maximum rate
To derive the actual flowrate, weneed the fluid Vaverage
The speed vector has parabolicpattern
Use approximation to get Va
Vaverage = 0.50 x Vmax
For actual flowrate, use caliperreading
Vmax
Vaverage
Matching the Reynolds number isnot, on its own, sufficient toguarantee flow similitude
Fluid flow is generally chaotic, andsmall changes to shape and surfaceroughness can result in very differentflows
The prominent reference isTechnology of Artificial Lift Methods,Volume 1 (Brown & Beggs)
Turbulent Flow
Vmax
Vaverage
Turbulence is related to theReynolds number, NRe of the fluid flow
If NRe < 2000 , flow is laminarIf NRe > 2000, flow is turbulentCOPYRIG
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Turbulent Flow
Vmax
Vaverage
In turbulent flow, the relation between Vmax and Vaverage is more complex.
Turbulence is related to theReynolds number, NRe of the fluid flow
If NRe < 2000 , flow is laminarIf NRe > 2000, flow is turbulent
A multiphase flow is ALWAYS
TURBULENT
Vaverage = 0.83 x Vmax
* Two-Phase means “non-miscible”
Two-Phase Production Fluid Flow Regimes
Deviated hole: dispersed oil on higher side and single-phase water on lower side
Sub-horizontal well: single-phase oil flows on higher side while single-phase water flows on lower side with thin mixing zone
Sub-vertical well: oil and water (mixed) across the wellbore
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Two-Phase* Production: Fluid Flow Regimes
* Two-Phase means “non-miscible”
Multiphase flow regimes vary along the well with:• Phase densities• Well deviation• Average velocity• Holdup• Interfacial tension• Phase viscosity
Two-Phase* Production: Fluid Flow Regimes
* Two-Phase means “non-miscible”
Liquid-Gas Flow Regimes102
10
1
10-1 1 10 102 103
GAS VELOCITY
LIQ
UID
VE
LO
CIT
Y
BUBBLE FLOW
PLUG FLOWSLUG FLOW
MIST FLOW
REGION I
REGION II REGION IIICOPYRIGHT
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Remarks:
If Area A = Area B no water production is observed at surface.
In extreme cases, the bottom hole water content may be close to 1 (100%), without water production reaching surface, except traces, sometimes.
Top casing
Bottom casing
Apparent Velocity Profiles in Well
A
Two-Phase Production: Logging in Deviated Hole
Effect of the logging tool running direction (UP vs DOWN)
LOGGING DOWN
oil
water
Apparent up flow
Apparent down flow
Tool Positioning in Well According to Logging Direction
B
STATIONARY
LOGGING UP
Two-Phase Production: Logging in Deviated Hole
Velocity Profile in Well with Water Cycling at Bottom Hole
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A = Pipe free cross sectionQt = Total FlowrateVs = Slippage VelocityVo = Oil VelocityVw = Water VelocityYw = Water Holdup
Flowmeter and GradiomanometerAnalysis
R&D Model Flow Assumptions
Modelling of Two-Phase Flow (Water & Oil)
Qo = (1 ‐ Yw) A Vo Qw = Yw A Vw
Yw A
Vo = Vw+ Vs Vw
“Holdup” Assumptions
WATEROIL
(1 ‐ Yw) A
Two-Phase Flow (Water & Oil)
Slippage velocity
Holdup = Heavy phase fraction @ depth = Yw
In the expression above:
“A” cross section bears a factor 1.78 which is a units conversion factor (see next)
Yw + Yo = 1
Yw = ( ρt – ρo ) / ( ρw – ρo )
where ρt is the Gradiomanometer reading @ depth
where A = Flow Area = ( Areacsg – Areatool) x 1.78
and
Vs = Vw–Vo
Qo = (1 –Yw) x (Qt + Vs x A x Yw)
Qw = Yw x [Qt – A x Vs x (1 –Yw)]
Part 2
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(convert ft to inches)
Section A = π / 4 ID2 (in2) Slippage Vs = ft/min
Thus, when multiplying, the units for A x Vs are: in2 x ft/min
To convert the mathematical A x Vs expression to bbl/day
Resolving Flowmeter Equation Units
Solving the above results in the value of: 1.78 bbl / day
in2 x ft/min x 12
(convert cu. in to bbl)in2 x ft/min x 12 x 1.03 x 10-4
(convert min to day)in2 x ft/min x 12 x 1.03 x 10-4 x (24 x 60)
This chart shows the correlation predicting slippage velocity as afunction of fluid parameters in vertical wells.
Water Holdup Chart (Vertical Well)
Slippage Velocity. Courtesy of Schlumberger.
(3)
(6)
(9)
(12)
(m/m
in)COPYRIG
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In deviated wells, the slippage velocity Vs curve takes the shapebelow.
Note that Vs is maximal when the heavy phase fraction is low, andthat Vs increases with deviation.
(31)
(15)
(m/m
in)
(3)
(6)
(9)
(12)(m/m
in)
Slippage Velocity (Deviated Wells)
Oil – water
Gas – liquid
Asymmetrical Threshold Velocity
Asymmetrical threshold?• Asymmetry of tool
hardware betweenlower and uppersurface of propeller
• Possible high level offriction at lower speeds
• Tool surface at timesseen differently byfluids, depending onthe direction of tooldisplacement
2 x Vt =2 times
threshold velocityCOPYRIG
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Two-Phase Flow Segregation
Why negative thresholds?• In deviated holes, fluids segregation is observed: oil flow is faster on
the upper side of pipe, so water will flow on the lower side.• Flowmeter “sees” oil while logging down and water while logging up,
so the apparent value of threshold looks negative.
Large water cut is steady ormoves up slowly
Oil moving on upperside of casing
Part of water is displaced by oil towards
bottom of well
Oil entry
Fast fluid segregation
Manual Diphasic Interpretation Procedure
• Logs: GR, flow, pressure, density, temperature… • Detailed recap and status of operations• Fluids PVT data• Well geometrical data
Critical analysis of logs and recorded data1
• Read spinner response (up and down at different cable speed + stations)• Plot diagram for in-situ calibration• Calculate slope for each response line• Determine threshold velocity for each stations where reversal occurs• Determination of apparent fluid velocity Vaverage
Logs depth correlations (mandatory)2
Selection of zones and stations for analysis3
Determination of average velocity per zone4
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Calculation of fluid PVT characteristics5
• Bubble point pressure, Rs, Rsb (when oil)• In-situ properties• Volumetric factors (oil, gas, water)
Manual Diphasic Interpretation Procedure
• Evaluation of correction factor, according to Re, Reynolds number
Determination of average flow for each zone6
Calculation of fluid PVT characteristics5
• Bubble point pressure, Rs, Rsb (when oil)• In-situ properties• Volumetric factors (oil, gas, water)
Minimum data needed:
Manual Diphasic Interpretation Procedure
• Evaluation of correction factor, according to Re, Reynolds number
Determination of average flow for each zone6
• Density of stock tank oil• Gas density• Water salinity• Oil GOR
Minimum data needed:
• Specific gravity and viscosity of mixture• Casing ID• Spinner OD• Oil GOR
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Calculation of volume fractions (“Holdup of heavy phase”)9
Correction of pressure gradient measurements (high flowrates, if necessary)7
Selection of diphasic interpretation model per zone8
• Friction• Inclination
• Oil-water or liquid-gas
Manual Diphasic Interpretation Procedure
Calculation of volume fractions (“Holdup of heavy phase”)9
Correction of pressure gradient measurements (high flowrates, if necessary)7
Selection of diphasic interpretation model per zone8
• Friction• Inclination
• Oil-water or liquid-gas
Minimum data needed:
• Wellbore ID • OD of Gradiomanometer tool• Density and viscosity of mixture• Average corrected mixture flowrate
Minimum data needed:
• Bubble point pressure, when oil present• Bottom hole flowing pressure• Corrected pressure gradient• Water cut
Manual Diphasic Interpretation Procedure
Minimum data needed:
• Corrected pressure gradient• In-situ phase densities
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Calculation of flow rates at surface conditions12
Evaluation of slippage velocities between phases10
Calculation of flow rates at bottom hole conditions11
Manual Diphasic Interpretation Procedure
Calculation of flow rates at surface conditions12
Evaluation of slippage velocities between phases10
Calculation of flow rates at bottom hole conditions11
Minimum data needed:
Minimum data needed:
Minimum data needed:
Manual Diphasic Interpretation Procedure
• Holdup • In-situ phase densities
• Average corrected mixture flow rate• Holdup• Slippage velocity
• Volumetric factors (Bo, Bg, Bw)• Rs (GOR)
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Approximation for Three-Phase Flow
• For oil and gas with low water cut (saturated reservoir), water will flow at same velocity as oil.
• For oil and gas with low amount of free gas (reservoir close to bubble point conditions), gas will flow at same velocity as oil.
• For gas and water with low amount of oil (condensate reservoirs), oil will flow at same velocity as water.
The procedure applied to diphasic flow can be used to get an approximate solution when three phases are present in the well, especially if the third phase contribution is low compared to others.
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Production Logging Fundamentals
Learning Objectives
By the end of this lesson, you will be able to:
Review the application of recent advances in cased hole logs indeviated and horizontal wells
Present actual field applications of production logs in three-phaseflow
Illustrate how production logs can assist water shut-off decisions
Part 1
Production Logging in Three-Phase Flow
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In sub-horizontal wells flowing in multiphase mode, smallchanges in well inclination and flow regime influence theflow profile.
Multiphase fluid flow in deviated and horizontal wells canbe very complex, primarily due to phase segregation withgravity.
Most highly deviated and horizontal wells will not havesufficient velocities to keep the fluid phases in the mixtureand thus phase separation will occur.
Challenges in Three-Phase Flow
Stratified Flow Wavy Stratified Flow
Plug Flow Slug Flow
Dispersed Bubble Flow Annular Flow
Challenges in Three-Phase Flow
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Gas-liquid flow regimes vary with:
• Relative differences in phase densities• Deviation• Average velocity• Proportion of each phase, holdup• Interfacial tension• Viscosity of each phase
Challenges in Three-Phase Flow
Logging vendors research the development of tools thatcan quantify the flow characteristics of fluids in these newwell standards.
• Schlumberger has identified that the traditional productionprofile logging is valid in wells with less than 20 degreedeviation.
• In deviations between 20-85°, the cross-sectional flowpatterns are much more complex due to phase separationwhich causes varying flow velocities and volumesoccupied by each phase.
Heavier fluid phase moves along the bottom of the flowarea, and flows slower than a lighter fluid phase.
The volume occupied by the cross section is notnecessarily equivalent to the relative flow distributionmeasured at the surface.
• This is called Stratified Flow.
Challenges in Three-Phase Flow
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When well deviations are in the range of 85-95°, the flowbecomes very stratified.
It is important to identify the individual phase volumesacross the tubular as well as their respective flowvelocities.
Diphasic flow of either oil/water or gas/water can be easilyidentified with the new generation of logging sensors andtools.
The presence of free gas in an oil/water system can resultis as many as six different major flow regimes.
For any given flow rate, the hold-up and velocity profile ofeach phase will vary with the well deviation.
Challenges in Three-Phase Flow
Challenges in Three-Phase Flow
Flow patterns transitions need continuity of correlations whencalculating pressure losses.
Incr
easi
ng
Vel
oci
ty
Increasing Liquid Hold-Up
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Three-Phase Flow
The mathematical modelling of three-phase flow is not wellmastered and little research has been achieved on suchconditions, and on slippage velocities.
In theory, values of flow rates and fluid velocities should bemeasured in each cross section of the pipe.
Then, all those data should be integrated to derive flow rates ofeach individual phase.
This is hardly possible because most measurements are notvalid, or not even possible to realize at the same time.
The only way out is to try and solve flow equations globally in-situ.
In three-phase flow, there are no correlations forrelative fluid velocities and slippage velocity.
With conventional tools, it is usually impossible todirectly obtain phase velocity measurements.
Slippage velocities might need to be derived fromcorrelations in two-phase mode.
• Slippage velocity oil-water: Vsow = Vo – Vw
• Slippage velocity gas-water: Vsgw = Vg – Vw
This approach is sometimes incomplete.
Three-Phase Flow
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Three-Phase Flow Investigation Methods
New logging devices enable identification of various fluidsflowing, and allow the computation of the fraction of total flowthat each fluid represents.
With the constituent fluids thus identified, downhole flow ratemeasurements are much more meaningful.
Both the fluid mixture and velocity must be considered inselecting appropriate logging devices.
The highest benefits of a device that measures fluid densitiesare obtained when defining gas entry into liquids.
For oil-water mixtures, the specific gravities are closer to eachother and resolution is difficult.
• Measurement of parameters that vary sufficiently for reasonableresolution between the constituent fluids of a multi-phase flow.
Three-Phase Flow Investigation Methods
Volume fractions are determined by using a setof appropriate tools. Volume fractions are determined by using a set
of appropriate tools.
If the velocity of one phase can be measureddirectly, then the flow rate of that phase can becalculated from:
If the velocity of one phase can be measureddirectly, then the flow rate of that phase can becalculated from:
If at least 2 phases velocities are directlymeasured, the third one can be calculated bydifference from total flow.
If at least 2 phases velocities are directlymeasured, the third one can be calculated bydifference from total flow.
Qi = Vi Yi ACOPYRIG
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Three-Phase Flow Equations
• A is the tubular cross section open to flow
Expanding to three-phase flow can be attempted with the samelogic as for two-phase flow by deriving the following equations.
The flow rate of each phase may be written as:
• Oil Rate:
• Sow is the slippage rate oil-water:
• Sog is the slippage rate gas-oil:
• Sgw is the slippage rate gas-water:
• Water Rate:
• Gas Rate:
Sow = Yo Yw Vsow A
Sog = Yo Yg (Vsgw – Vsow) A
Sgw = Yg Yw Vsgw A
Qo = Yo Qt + Sow – Sog
Qw = Yw Qt – Sow – Sgw
Qg = Yg Qt + Sog + Sgw
Three-Phase Flow Equations
Thus, 5 independent measurements are needed to solve thesystem. For instance:
• Gradiomanometer• Capacitance• Nuclear Densimeter• Pulsed Neutron• Carbon Oxygen Tools
Qo = Vo Yo A
Qw = Vw Yw A
g g gQg = Vg Yg A
Yo + Yw + Yg = 1
Qo + Qw + Qg = Qt
This is a system of 5 equations
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GHOST Tool Arrangement Overview
GHOST: Gas Holdup Optical Sensor Tool
Gas holdup =Time above threshold
Total time
Telemetry, gamma ray, CCL, pressure,
temperatureDensity, deviationDensity, deviation
Gas holdup, gas/liquid bubble count,
one-arm caliper, relative bearing
Gas holdup, gas/liquid bubble count,
one-arm caliper, relative bearing
Velocity, X-Y caliper, water holdup,
water/hydrocarbon bubble count, relative bearing
Velocity, X-Y caliper, water holdup,
water/hydrocarbon bubble count, relative bearing
GHOST Tool Arrangement Overview
GHOST: Gas Holdup Optical Sensor Tool Main Applications
• Run in combination with spinner to help quantify multiphase flow.• More realistic determination of gas hold-up at all well angles.• Locate fluid entries by hold-up and gas bubble count.• Possibly quantify gas flow from the hydrocarbon bubble count.• Locate gas-liquid interface in stratified multiphase horizontal flow.• Can be run in memory mode on slick line as well as with a tractor
and/or coiled tubing.
Limitations• CANNOT discriminate between oil and water phases.• Will not work in emulsions, when gas bubbles are larger than 3mm.• If bubble velocity is higher than 6 ft/sec (2 m/sec), the tool is not
effective and classical density tools can be used.
Part 2
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GHOST Tool Arrangement Overview
GHOST: Gas Holdup Optical Sensor Tool Operating Technique
• The best results will occur when the flow is towards the tips of theprobes.
• These probes can be placed at 3 different distances from thewellbore wall with low rates being closer to the outside and turbulent,or poor hole conditions being closer to the inside.
• When this tool is run with the normal PSP (Production ServicesPlatform) logging string, the four probes are mounted on thecentralizer arms of the Full Bore Spinner.
WFL gives the possibility to treat water independently fromother fluids by measuring Vw and, in favorable cases, Qw(from TDT log) or Yw (using RST log).
Three-Phase Flow Logging Methods
Direct measurement of water flow velocity has been donesince the 1990’s with the WFL (Water Flow Log).
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Water Flow Log Principle
The water velocity is computed from the time of travel of neutron-activatedoxygen of water between the neutron generator and the near and far detectors.
The tool "vertical" (i.e., well depth) resolution is the distance between generatorand detectors.
Flow direction
Three-Phase Flow Investigation Methods
• This slug can be detected by a standard pulsed-neutron capture tool, andthe velocity of the phase is computed from the time of travel betweenejector and detector.
• Gadolinium has a high capture cross section, or sigma, so that a slug offluid with high sigma moves with the appropriate phase up the borehole.
• In a typical chemical marker technique, a gadolinium-rich marker isinjected into the flow stream, dissolving in either oil or water.
Velocity-shot measurements, using radioactive tracers, havealso been used.
Velocity-shot measurements, using radioactive tracers, havealso been used.
• Phase velocity measurements are made with either the cross-correlationflowmeter, the Water Flow Log, or with chemical markers designed to mixspecifically with one particular phase.
• This is particularly important in highly deviated and horizontal wells withmulti-phase flow, where the flow pattern is complicated.
PVL (Phase Velocity Log) measures directly Vo and Vw, whenchemicals solved in water, or oil, are used.
PVL (Phase Velocity Log) measures directly Vo and Vw, whenchemicals solved in water, or oil, are used.
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Phase Velocity Log Principle
The water velocity is computed from the time of travel of an oil-miscible marker between between the ejection nozzle and the ReservoirSaturation Tool (RST).
The tool "vertical" (i.e., well depth) resolution is the distance betweenejector and detector, i.e., 25 ft (7.3 m).
Oil miscible marker
Phase velocity = L/T
PVL L (usually 7.3m) RST
Water Holdup Measurement: FloView Probe
• The FloView holdup probe (no spinner) measures the bubble count (light phase) in dispersed phase by taking 4 independent measurements in 4 pipe quadrants.
• Measurement of the bubble count of the light phase of the stream is converted to velocity at the station of measurement.
• FloView can provide the velocity of the dispersed phase, derived from the displacement speed of bubbles.
Holdup is a calculation of the volume ratio that the water occupies in the wellbore.
The Water Hold-Up Tool (Capacitance Tool) is sensitive to the dielectric constant of the flowing stream.
• Wellbore fluids flow through a tool chamber that acts as a capacitor in an oscillator circuit.
• The capacitance varies with changes in the dielectric constants of the fluids flowing through the chamber.
• The Capacitance Tool is used to identify the oil, gas, and water phases in highly deviated and horizontal wells.
– The tool carries several individual sensors around the circumference of the wellbore which provides the fluid phase distribution over the cross-section of the hole.
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Water Holdup Measurement: FloView Probe
• The FloView holdup probe (no spinner) measures the bubble count (light phase) in dispersed phase by taking 4 independent measurements in 4 pipe quadrants.
• Measurement of the bubble count of the light phase of the stream is converted to velocity at the station of measurement.
• FloView can provide the velocity of the dispersed phase, derived from the displacement speed of bubbles.
Water holdup =Time in short circuit
Total time
Water Holdup Measurement: FloView Probe
• The FloView holdup probe (no spinner) measures the bubble count (light phase) in dispersed phase by taking 4 independent measurements in 4 pipe quadrants.
• Measurement of the bubble count of the light phase of the stream is converted to velocity at the station of measurement.
• FloView can provide the velocity of the dispersed phase, derived from the displacement speed of bubbles.
Holdup is a calculation of the volume ratio that the water occupies in the wellbore.
The Water Hold-Up Tool (Capacitance Tool) is sensitive to the dielectric constant of the flowing stream.
• Wellbore fluids flow through a tool chamber that acts as a capacitor in an oscillator circuit.
• The capacitance varies with changes in the dielectric constants of the fluids flowing through the chamber.
• The Capacitance Tool is used to identify the oil, gas, and water phases in highly deviated and horizontal wells.
– The tool carries several individual sensors around the circumference of the wellbore which provides the fluid phase distribution over the cross-section of the hole.
Low frequencies correspond to high-dielectric-constant fluids (water), and high frequencies correspond to low-dielectric constant fluids (hydrocarbons).
The tool can differentiate between water and hydrocarbons, but it can give erroneous results in stratified flow applications.
It is necessary to calibrate the tool so that water hold-up can be calculated from the oscillator frequency.COPYRIG
HT
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Water Holdup Measurement: FloView Probe
• The FloView holdup probe (no spinner) measures the bubblecount (light phase) in dispersed phase by taking 4 independentmeasurements in 4 pipe quadrants.
• Measurement of the bubble count of the light phase of the streamis converted to velocity at the station of measurement.
• FloView can provide the velocity of the dispersed phase, derived from the displacement speed of bubbles.
Holdup is a calculation of the volume ratio that the water occupies in the wellbore.
The Water Hold-Up Tool (Capacitance Tool) is sensitive to the dielectric constant of the flowing stream.
• Wellbore fluids flow through a tool chamber that acts as a capacitorin an oscillator circuit.
• The capacitance varies with changes in the dielectric constants ofthe fluids flowing through the chamber.
• The Capacitance Tool is used to identify the oil, gas, and water phases in highly deviated and horizontal wells.
– The tool carries several individual sensors around the circumference of the wellbore which provides the fluid phase distribution over the cross-section of the hole.
Low frequencies correspond to high-dielectric-constant fluids (water), and high frequencies correspond to low-dielectric constant fluids (hydrocarbons).
The tool can differentiate between water and hydrocarbons, but it can give erroneous results in stratified flow applications.
It is necessary to calibrate the tool so that water hold-up can becalculated from the oscillator frequency.
Water holdup =Time in short circuit
Total time
Main ApplicationsMain Applications
• Run in combination with spinner to help quantify multiphase flow.• Reasonable determination of gas/water hold-up at well angles.• Can also be run in memory mode on slick line as well as with a tractor
and/or coiled tubing.
LimitationsLimitations
• Frequency differences between the two hydrocarbon phases (oil andgas) are small and may be non-distinguishable.
• Erroneous results can be obtained in stratified flow applications wherethe detected fluid is predominantly only one of the fluid phases. This tends to occur in well deviations exceeding 45° but can also occur at lower deviations if the flow velocities are too low.
• Tool must be centralized.• Location of spinners may not identify the individual (different) velocities
of each phase, hence the necessity to carry several spinners.
FloScan Imager (FSI)
Optical GHOST probeMini spinner cartridge with integrated one-wire detector
Electrical FloViewprobe
New tools have furtherdeveloped the understandingand interpretation of highangle flow patterns, thussignificantly extending someof the more traditionalproduction logging technologyand interpretation techniques
Sensing probes are now onthe arm of the centralizer
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FloScan Imager (FSI)
Measures local fluid velocity
Measures water holdup
Measures gas holdup
The sensors are positioned to allow their measurements to yield a map of fluid velocities and holdups along a vertical diameter of the wellbore at every survey depth
FloScan Real-Time Logging
Flowrate data and phase distribution can be analyzed
and recorded in real-time by the Flow Scanner.COPYRIG
HT
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Conventional Spinner vs FloScan Spinners
Conventional Spinner FloScan Spinners
Computer Processed Interpretation
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Conventional PL vs FloScan Imager
Conventional PL vs FloScan Imager
The resulting production of 556 BOPD (barrel of oil per day) and 2532 BWPD (barrel of water/day) represented a 9-fold increase in oil production.
• Inclination of well: 37°
• Producing with gas lift from 6 open intervals
• Production: 2058 B/D (barrel liquid per day) (327 m3/d)
• Water cut: 97%
As a result, 90% of the oil production was erroneously attributed to the lower perforations
with the conventional tool analysis.
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Back to Work Suggestions
Meet with a production engineer in your group and ask for a production log waiting for interpretation.
Practice by yourself and compare your views and conclusions with those of specialists.
Get some additional explanations where grey areas remain.
Back to Work Suggestions
Meet with your supervisor to be assigned to witness/ participate in an actual logging job.
On the job, run a real-time log interpretation, suggest additional or repeated logging passes, diagnose log data quality and conclude.
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PetroAcademyTM Production Operations
Production Principles Core Well Performance and Nodal Analysis Fundamentals Onshore Conventional Well Completion Core Onshore Unconventional Well Completion Core Primary and Remedial Cementing Core Perforating Core Rod, PCP, Jet Pump and Plunger Lift Core Reciprocating Rod Pump Fundamentals Gas Lift and ESP Pump Core Gas Lift Fundamentals ESP Fundamentals Formation Damage and Matrix Stimulation Core Formation Damage and Matrix Acidizing Fundamentals Flow Assurance and Production Chemistry Core Sand Control Core Sand Control Fundamentals Hydraulic Fracturing Core Production Problem Diagnosis Core Production Logging Core Production Logging Fundamentals
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