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Production Logging

Introduction

3
Production Logging
• Production Logging encompasses logging techniques to
measure dynamic and static wellbore and reservoir
parameters including a flow measuring device.

4
Production Logging Objectives
• Monitor reservoir performance
• Diagnose completion problems
• Evaluate treatment effectiveness

5
Reservoir Performance
• How much fluid is produced?
• Where is the fluid coming from?
• What type of fluid is produced?
• Where is the fluid going?
Gas Cap
Oil Zone
Wellbore
How much of What fluid coming from Where?

6
Completion Problems
• Casing leaks
• Tubing leaks
• Packer leaks
• Poor cement bond
• Plugged perforations
Casing leak
Channel
Low Pressure Oil Reservoir
High Pressure
Water Sand

7
Treatment Effectiveness
• Squeeze cement jobs
• Bridge plugs
• Hydraulic fracturing
• Acid treatments
• Conformance treatments
Intermediate
Permeability
Low
Permeability
High
Permeability
Wellbore
Casing
Cement
Intermediate
Permeability
Low
Permeability

PL Objectives

9
Production logging Objectives
• Flow profile / Injection profile per zone
• Split of production between the phases: oil, gas and water
• Locate water entries
• Locate oil and gas production zones
• Locate low efficiency perforated intervals
• Temperatures and pressures
• Locate cross flow between different zones
• Mechanical Integrity (Casing Leaks / Tubing leaks / SSD Leaks)
• Locate flow behind the casing.
• Detect intervals affected by damage or skin
• Perforating Effectiveness
• Productivity Index (SIP)
• Reservoir Monitoring & Problems Diagnostics

10
Types of Production logs
• A production logging survey depends on:
• The type of the Well
• The Type of the Survey
• The Logging Method

11
Types of Production Logging Surveys
• There are many types of Production Logs, depending on the objectives of the test:
• Stationary
• Flowing
• Build-Up measurements
• Multipasses Method (Passes up and/or down)
• Any combination of Pressures, Temperatures, Densities, Hold-ups, Phase velocities....
They all have one thing in common
Downhole Production Measurement Device

12
Production Logging In The Classic Way
• Client identifies problem
• Service Company proposes Production Logging program
• Service Company acquires data
• Service Company does interpretation
• Client and Service Company discuss the results. Often a discussion with the
logs on the table and hand-waving arguments.
• Client decides on the plan of action based on the results

13
Evolution of Production Logging - Present Day
• Interpretation tool (Software) is in the hand of the Client.
• Clients integrates results with information from other sources
• Client develops knowledge
• Client sees opportunities for the tool: programs are tailored to the needs of the
client
• Client asks for further development of the software and hardware: cooperation
drives development
• Client becomes driver: takes control of the process

14
Well Production
• Oil rate of each individual reservoir is governed by:
• Pressures
•Reservoir pressure (Pr)
•Well pressure (Pwf: Pressure well flowing)
•Well head (WHP)
• Water cut
• Gas cut
• Lift dynamics (Production method)
• Performance of gas reservoirs is almost exclusively driven by pressures.
• But water and condensate can hamper production severely

15
Ultimate Production Log Analysis Software
• Quick Wellsite Analysis to Determine:
• Data Quality and Quantity
• Diagnose Unexpected Results
• Easy to Use for Field Personnel
• Advanced Options for Expert Users
• Complete Flow Analysis Including:
• Complete PVT Capabilities
• Holdups
• Phase Velocities
• Downhole and Surface Flow Rates

16
Design Of Logging Program
• Is the well flowing in a steady state?
• Wait until stabilization occurs
• Change chokes size
• Multiple spinner passes to determine correct Apparent Velocity profile
• 30, 60, 90, 120 Up and down
• Stationary measurements to confirm flowmeter, holdup/temperature and
pressure readings
• Shut-in passes for buildup pressure readings
• Determination of thief zones (cross flow)
• In-situ calibration of spinners/ holdup devices

Production Logging
Tools

18
Production Logging Tools - SONDEX
• Telemetry
• Gamma Ray
• CCL
• Flowmeter (Fullbore Spinner - Continuous Spinner)
• Temperature
• Capacitance
• Flowmeter (Inline Spinner)
• Pressure
• CCL
• Density
• Centralizers

19
PL Tool String
PL Tool String
Quartz Pressure
Capacitance
Temperature
Fluid Density
Centralizer
Inline Spinner
Fullbore Spinner
CFB
CCL
CCL
Gamma Ray
Telemetry
Centralizer

Production Logging
Procedure

21
A
B
C
Flowmeter
(rps)
-15 60
Cable Speed
(ft/min)
120 -120
Temperature
(Deg F)
240 250
Density
(gr/cc)
0.5 1
Pressure
(psi) 27K
2500 3000
Capacitance
(cps) 33K
Gamma Ray
(API)
CCL
Production Logging Procedure

Flowmeter
(Spinners)

23
Flowmeter
• A flow-meter measures flow rate in terms of fluid velocity.
• The rotation is linearly proportional to the flow velocity
• The spinner rotates clockwise or counter clockwise depending on the fluid
direction and the relative velocity of the fluid with respect to the tool.
• It is one of the most important tool in the string.
• During the processing the RPS are converted into Velocity and the Velocity is
converted into flow Rate

24
• Caged Fullbore Flowmeter (CFB 3 arm, CFB 6 arm)
• Continuous Flowmeter (CFS)
• Inline Spinner Flowmeter (ILS)
• Diverter Basket Flowmeter (DBT)
Types of Flowmeters

25
Caged Fullbore Flowmeter – 3 & 6 Arm
• Fullbore flow meter is self centered at the middle of the well bore
• The mechanical section is available in different sizes to cover the
different casing size.
• There are standard stand alone tools and as part of the short stack
(CTF)
• Allows a large diameter impeller to pass through small diameter tubing
• Accurate flowrates covering the cross sectional area of the casing.
• 3 Arm Caged Full Bore (CFB) helps to support the weight of the tool in
highly deviated wells acting as a centralizer.
• The Flowmeter is closed while running in hole, opening automatically
when it leaves the tubing to enter the casing.
• The 6 Arm Caged Full Bore Flowmeter provide more protection to its
impeller when used in wells with large ID, gas lift mandrels and in
horizontal wells.
3 Arm
CFB
6 Arm
CFB

26
Continuous Flowmeter - CFS
• The Continuous Flowmeter has a fixed OD and impeller diameter.
• Works in Tubing and Casing
• Spinner is protected by the case wall
• In very high fluid velocity wells CFS could be a better tool to run than the CFB
• Sensitive to problems of plugging with debris.
• If there are debris in the wellbore CFS with 3 side windows in the impeller
housings is recommended to allow debris to escape
• Sizes : 1-3/8”, 1-1/2”, 1-11/6” , 2-1/8, 3-1/8”

27
Inline Spinner Flowmeter (ILS)
• Mainly used as an alternate spinner or it is the only spinner when used with CFB
to measure inside the tubing.
• Three different sizes are available 1 11/16”, 2-1/8” or 3-1/8” OD .
• As it is not a bottom tool there is influence to the flow due to tool body.
• If possible according with the minimum ID a larger spinner than the diameter of
the tool could be used

28
Diverter Basket Flowmeter (DBT)
• The tool utilizes a patented fabric diverter element to divert wellbore
flow up through a modified in-line spinner.
• Its main application is to measure very low flow rates. It is done by
reducing the flow cross-sectional area forcing all the fluid to pass
through the spinner housing
• In multi-phase wells the tool minimizes the effects of fluid segregation.

Flow Profile

30
Flow Profile
• Vertical distribution of the oil, water and gas rates
produced through the perforated intervals
• Have to be measured under stabilized conditions, at
different rates and also with the well shut-in

31
2500 BPD…50 ft/min...
1500 BPD
1000 BPD
How the flow is measured?
• Using a Flowmeter in the center of the hole (Centralized)
• The flow doesn’t have to measured in front of the producer zone. The flow
have to be measured in the top and bottom of the producer zone. (In the
calibration zones)

32
Apparent Fluid Velocity
PLT Passes
Calibration Plot
Rates
Stationary Readings A
B
C
Flowmeter
(rps)
-15 60
Apparent Velocity
(ft/min)
-10 90
Flow rate
(stb/d)
0 0
Total Flow Rate
(stb/d) 5000
5000
QA
QB
QC
Qc
QB+Qc
QA+QB+Qc
Multipasses Method

33
C
B
A
Flowmeter (rps)
-15 60
Cable Speed
(ft/min)
120 -120
1.- PLT PASSES
3.- CALIBRATION ZONES
4.- CALIBRATION PLOT
-90 30 60 90
-60 -30
-120
5
10
20
30
40
50
-10
-5
Cable Speed
(ft/min)
Vs
Angular Velocity
Rps
2.- STATIONARY READINGS
Multipasses Method

34
-90 30 60 90
-60 -30
-120
5
20
40
50
-10
-5
Angular Velocity
Rps
Cable Speed
(ft/min)
Flowmeter
(rps)
-15 60
Cable Speed
(ft/min)
120 -120
A
B
C x x x
x
30
10
Calibration Plot

35
A
B
C
Flowmeter
(rps)
-15 60
Apparent Velocity
(ft/min)
-10 90
Flow rate
(stb/d)
0 0
Total Flow Rate
(stb/d) 5000
5000
QA
Q=1.4* Vapp*ID²
ID
QC1 =1.4* *ID²
QC2 =1.4* *ID²
QC3 =1.4* *ID²
QA = QC1 –QC2
QB = QC2 –QC3
Qc = QC3 –QC4
QB
QC
QC4 =1.4* *ID²
QC4 =0
Qc
QB+Qc
QA+QB+Qc Factor to use Vapp in ft/min
and ID in inches to obtain
rates in B/D
Rate Calculation

Temperature

37
• Temperature is one of the most useful “auxiliary” measurements made in
production logging.
• Combined with pressure it helps compute the PVT parameters.
• In addition it will detect very small fluid entries and their flow.
• Gas entries, for example, are characterized by a sharp reduction in
temperature.
• It is the only tool in the string that “sees” behind casing, hence it will detect
channeling.
• The temperature gauge is in direct contact with the fluids in the wellbore and
respond to all the changes of the system (Inside the wellbore and behind the
casing)
Temperature

38
Temperature Tools
Response Time <0.5 seconds
Resolution 0.006 °F (0.003 °C )
Accuracy 0.9 °F (0.5 °C)
Linearity 0.5 °F (0.15 °C)
Principle of operation:
• The sensor of the tool is a platinum resistor, in the form of a needle for rapid
response
• Changes resistance with temperature , causes a varying voltage difference across
the probe which is used to drive an oscillator.
• The original frequency is multiplied 64 times by a phase lock loop multiplier so as to
increase the resolution.
• The frequency is counted and sent to the memory tool/ surface system
CTF
PRT

39
Temperature
The temperature of a formation/well follows the regional geothermal gradient

40
Earth Thermal Conduction
Lime
Shale
Dolomite
Gypsum
Anhydrite
Sand
Temperature Increases
Thermal Conductivity
kh (Btu/hr-ft-ºF)
1.058
1.692
1.952
2.307
Depth
(feet)
Temperature (ºF)
1.5 ºF/100’
1.1 ºF/100’
2.4 ºF/100’
1.3 ºF/100’
Q
Ts
dT/dD
Different layers of different
materials of different thermal
conductivity will have the effect
of having different gradients.

41
Temperature tool Logging and Log Quality
Logging job operations
• The probe has very thin attachment wires it should be protected from shock
• The best logging data is with a line speed of around 30 ft/min.
Log quality control
• The correct calibrations must be entered into the logging software.
• Tool cage must be kept clean. Running the tool into the bottom of the well can introduce mud or
debris and into the sensor window.
• The best data will be from logging against flow and into fresh fluids.
• Line speed – the optimum line speed is 30 ft/min.
• Different fluids have different thermal conductivity. In a shut in well slight temperature changes
may be seen at fluid interfaces and temperature changes when the tool is in gas may be slow
compared to fluids.

42
Temperature tool Logging and Log Quality
Log quality control
• There is normally a cooling effect where gas enters the wellbore. However above about 7,500
psi this cooling effect may not be seen.
• Flowing temperature will be above geothermal with water and when oil flow is above bubble
point.
• In zones of no flow, at the same line speed temperature curves should overlay.
• The thermal mass of the toolstring can itself influence the temperature profile. When this is
critical, position the temperature sensor at the bottom of the toolstring.
• Check on the depth correlation, noticeable temperature changes should be on depth in
relation to the perforations, formation or completion items.
• Expect temperature changes when the spinner tool shows fluid entry.
• Observe minor temperature changes with change in fluid type.

43
Temperature Interpretation
• The interpretation of temperature logs relies on patterns.
• The change in temperature with respect to the geothermal gradient has to
be noted.
• Heating means a fluid is flowing from deeper to shallower
• Cooling means a fluid is injecting from shallower to deeper.
• The temperature is much more sensitive to small flows than the
flowmeters.

44
Temperature Profile example

45
Temperature (ºF)
gGA
TGeo
Temperature Well Flowing
• Fluid enters to the well
through the perforations
and continues flowing
upward
• The “hotter” fluid
increases the
temperature away from
the geothermal
gradient.

46
Flow rate Dependency
Temperature (ºF)
• While more production;
more temperature

47
Time Dependency
• While more time of
production. More close
to the true Flowing
temperature
Temperature (ºF)

48
Multiple Zones Producing Liquid
Temperature (ºF)
1000 B/D
800 B/D
Asymptote 1000 B/D
Asymptote 1800 B/D
Asymptote 2300 B/D
500 B/D

49
Water / Gas Injection
Temperature (ºF)
Temperature Injector Well
Injection Profile
Shut-in Profile
after Injection
Temperature coming back
to the Geothermal Gradient

50
Cross Flow
Temperature (ºF)
Temperature - Cross Flow
Up Flow
Cross Flow
Down Flow
Cross Flow
High Flow Rate
Low Flow Rate
CO1
CO2
CO3
SG1
SG2
RIH1
RIH2
T-GEO
Ρ=
1
gr/cc
Ρ=
0.78
gr/cc
Mhf1
Mhf2
Mhf3
Mhf4_MSF
Mhf4_SB
Mhf5
KhbSeq1mfs
2275 m
2279 m

51
Multiple Zones Producing – Gas Effect
Temperature (ºF)
1000 B/D
800 B/D
Asymptote 1000 B/D
Asymptote 1800 B/D
Asymptote 2300 B/D
500 B/D
Gas Effect
• When the Gas enter in the
wellbore occurs an
expansion. Due to its PVT
properties a cooling effect
can be observed.
• Oil above the bubble point
will have a heating effect.

52
Friction Effect
Temperature (ºF)
Asymtote 1000 B/D
Asymtote 1800 B/D
Asymtote 2300 B/D
1000 B/D
800 B/D
500 B/D
Friction Effect

Fluid Identification
Tools

Density

55
Density tool
• The fluid measure the average density of the fluid in the wellbore
coming from the perforated intervals.
• The main objective is determine the distribution of different kind
of fluids produced from the reservoir

56
Density Tools
• Gradiomanometer (mercury filled) (obsolete)
• Fluid density Differential pressure sensor (FDD)
• Nuclear fluid density tool (FDR)

57
Radioactive Density (FDR)
• When a gamma ray passes through the crystal it causes a photon of light to
be emitted (it scintillates)
• The signal is amplified using a photomultiplier tube to create a measurable
charge pulse.
• The pulses are detected and filtered for noise.
• The pulses are stored and if necessary divided down before sending to
surface
• The log of the count rate of the detected sources is in proportion to the
density of the fluids passing through the tool window.
• The relationship of the natural log of the tool response (counts) is
approximately linear over the density range between 0.0 to 0.90 g/cc. Above
1.0 g/cc the logarithmic response is also linear but the high concentration of
chlorine ions tends to absorb gamma rays which changes the slope of the
response
General Multipoint calibration
line end-points
Density Frequency
0 6.815 * gas freq
0.846 1.432 * oil freq
1.0 fresh water freq
1.2 0.447 * water freq
Calibration

58
Fluid Density
Air
0 g/cc
Water
1 g/cc
Diesel
0.8 g/cc
Gamma
Ray
Detector
Source

Capacitance

60
Fluid Capacitance (CWH)
• Its main application is to distinguish between water and hydrocarbons based on the
disparity in the Dielectric Constant of them.
• Tool has non linear response and it is very sensitive in the 0-40% water holdup
range, above this water becomes more dominant.
For qualitative interpretation it should be
noted that a trend towards a higher
frequency denotes hydrocarbon and a
trend towards a lower frequency denotes
water.

61
Fluid Capacitance (CWH)
• The tool is essentially an annular variable capacitor with
a central probe as one plate and the cage / housing of
the tool as the other plate.
• The well mixture flows between the plates.
• The average dielectric of the fluid mixture governs the
rate of charging of the capacitor.
• Water charges slowly low frequency
• Hydrocarbons high frequency.
• Measurement at the center of the casing.
Fluid K cps
Air 1-2 33,500 Hz
Oil 2-4 32,500 Hz
Fresh Water 80 27,500 Hz
Saline Water (100 Kppm) >80 27,000 Hz
Housing
Isolator
Electrode
Water
E
Oil
Casing
Calibration

Holdup

63
Holdup
• Percentage of the Cross-Sectional Area occupied for each phase present in
the Pipe.
Yg
Yw
Yo
Yg+Yo+Yw=1

64
Holdup
• Single phase does not require a holdup device
• Two phases require one holdup device
• Three phases require two holdup devices
• The Devices Cannot Measure Same Fluid Property
• Phases are at downhole conditions

65
Two Phase Holdup Calculations
• ρm = Measured Density
• ρl = Density of the Light Phase
• ρh = Density of the Heavy Phase
• Yh = Holdup of the Heavy Phase
• Yl = Holdup of the Light Phase
Yh =
ρm- ρ
ρ - ρ
l
l
h
Yl = 1-Yh
Holdup From the Fluid Density

66
Two Phase Holdup Calculations
Yw = 1-Yh
Holdup From the Fluid Capacitance Tool
Yh =
Hm-
-
Hw
Hh Hw
• Hm = Measured Hydro Reading
• Hw = Hydro Reading of Water
• Hh = Hydro Reading of Hydrocarbons
• Yh = Holdup of the Hydrocarbon Phase
• Yw = Holdup of the Water Phase

67
( ) ( )
Ho
Hw
Yw
Hg
Yg
Hm
Yo
×
−
×
−
=
( )
o
w
o
g
o
Yg
m
Yw
ρ
ρ
ρ
ρ
ρ
ρ
−
−
−
×
+
=
( ) ( ) ( )
( ) ( ) ( )
Hw
Ho
o
Hg
Hw
o
Ho
Hg
w
Hw
Ho
m
Hm
Hw
o
Ho
Hm
w
Yg
−
×
+
−
×
+
−
×
−
×
+
−
×
+
−
×
=
ρ
ρ
ρ
ρ
ρ
ρ
• Yg = Holdup of the Gas Phase
• Yo = Holdup of the Oil Phase
• Yw = Holdup of the Water Phase
Three Phase Holdup Calculation
Yg
Yw
Yo
Yg+Yo+Yw=1

Multiphase flow
rates

69
Rate calculation for Multiphase Flow
Qw = Yw * Vw * A
Qo = (1-Yw) * Vo * A
Yo = 1-Yw
Qo = Yo * Vo * A

Quartz Pressure

71
Quartz Pressure
• The gauge measures the pressure during the PLT passes
• The pressure measurement is a continuous profile of the pressure in the
wellbore.
• The curve reflects changes in the borehole fluid composition (density)
• The major reason to measure the pressure is to be able to accurately predict
the PVT properties of the fluids.
• It is possible to use the pressure as a density measurement. (derivative)

72
0.05 psi/ft
0.32 psi/ft
0.47 psi/ft
Depth
(ft)
Pressure (psia)
0.12 g/cc
0.79 g/cc
1.09 g/cc
Pseudo-Density (g/cc)
- Check Fluid Density tool accuracy when well is stabilized
- Use as Fluid Density in the absence of Fluid Density tool if the well is properly stabilized
Quartz Pressure

Log Quality Control

74
Log Quality Control
• Constant line speed in passes ± 3 ft/min
• Line tension quasi constant drag increase line tension with line speed in
upward passes and decrease line tension in downward passes.
• Depth match among all passes (Gamma Ray and CCL)
• Log length : 30 ft above perforations and 30 ft below perforations
• Stations 1 min above and below perforations
• Header fill in, Well diagram, Tool diagram Log Titles and Job Log
• Parallel Flowmeter passes

75
Log Quality Control
• Symmetric Flowmeter response at sump (zero flow)
• 6 passes are usually not enough
• Spinner Calibration Plots
• Pressures within ±5 psi among passes at the same depth
• Temperatures within ±0.1°F among passes
• Fluid Density within ±0.02 g/cc among passes
• Capacitance within ±200 Hz among passes (up and down sometimes
different)

Job Planning

77
Job Planning
• Job Program
• Multiple Rate Sequence
• Gradient RIH and POOH
• Reference Depth Selection for Well Testing
• Tool String Selection
• Well diagram
• Passes depth interval
• Tubing & Casing Size Fullbore Spinner selection
• Tubing End-Perf
• Perf-Sump
• Stationary Readings depth and duration

Examples

Example #1

80
Example #1 – Well Flowing

81
Example #1 – Well Flowing

Example #2

83
Example #1 – Well Shut-in
CROSS FLOW

84
Example #2 Well Before Stimulation
24/64” 32/64”
48/64” Shut-in

85
Example #2 Well Before Stimulation

86
Example #2 Well After Stimulation
24/64” 48/64”
Shut-in

87
Example #2 Well After Stimulation

Example #3

89

90

91

Example #4

93

94

95

96

97

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