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Production Logging Core
Learning Objectives
By the end of this lesson, you will be able to:
Present the principles of cased‐hole evaluation tools
Present typical applications and justification forrunning cased‐hole evaluation tools
Present conveyance methods for running cased‐hole evaluation tools in the field
Objectives and Domain of Application
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From a few basic sensors, production logging tools have evolvedto a family of tools each with sensors designed to makemeasurements that, once interpreted together, provide accurateflow rates estimates for multiphase flow and determine preciselywhere the various fluids are entering (or exiting) the borehole.
As well trajectories continue to grow in complexity, progressingfrom vertical to deviated and horizontal and introducing newchallenges in completion design and flow assurance, thedevelopment of new production logging technologies has helpedfor the understanding of downhole completion efficiency.
Production Logging Introduction
Logs are run after the well is completed.• Surface flow measurements are usually not adequate to assess the
efficiency of the downhole production or injection system.• Logs are run in order to acquire a range of downhole
measurements.• Usually, requested and analyzed by Production Engineers.
Purpose is to diagnose well integrity and evaluate fluid flowinside and (possibly) outside the pipe along the well path.
• Most common application of production logging is to obtain thedownhole well flow profile and measurement of fluid flowdistribution.
• Numerous other applications, such as the detection and evaluationof tubing leaks and channels behind casing.
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Production Logging Tools Conveyance: Coiled Tubing
Coiled Tubing Advantages:
1. All conventional tool combinations and services may be run on the coiled tubing logging string.
2. Continuous data recording is possible while running in and logging out of the borehole.
3. Mud treatment or formation stimulation can be undertaken through the coiled tubing, while the logging tools are in the well, allowing the in-situ evaluation of treatments to take place.
Production Logging Tools Conveyance: Tractor
Courtesy Welltec
Connects to the wireline through mono or multi cable heads
Top Connector
Wheel Sections
Wheel sections can be optimized to maximize speed or traction
Connects to the mono or multi line logging tools below the Well Tracker
Bottom Connector
Electrical tools used to push the tool string into hole, overcoming wireline's disadvantage of being gravity dependent.
Engineered to be used in high-angle and horizontal wells to deploy downhole tools previously conveyed by coiled tubing or drillpipe.
Intelligent tractors can be run through complex completions and long horizontal sections.
Permits well data to be acquired during downward, as well as upward, passes.
Automatically monitored and controlled from surface so it achieves much greater flexibility than traditional systems.
Used to convey logging and perforating tools or to gather detailed information about downhole conditions.
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Wells with surface pressure typically have a completion tubing of relatively small internal diameter ID, compared to the casing size across the reservoir.
Cased hole toolstrings for live wells are
typically sized at 1-11/16" (42.9 mm) in order to pass through the smallest nipple
in a 2-3/8" (60.3 mm) tubing. The configuration of the tool string is determined from the objectives of the logging program and the composite Production Logging Tool (PLT) is assembled from various tools according to specific local needs.
The tool string is run in collapsed condition through tubing and opens to full operational configuration when reaching full casing diameter below mule shoe.
Composite Production Logging Tool Geometry
(6.9
)
(13.
8)
(20.
7)
(27.
6)
(34.
5)
(41.
4)
(48.
3)
(55.
2)
(62.
1)
(69.
0)
(mPa)
(18)
(36)
(54)
(73)
(91)
(109)
(127)
(145)
(163)
(181)
(200)
(218)
(236)
(254)
(272)
(290)
(308)
(kg
)
(0.32 cm)
(0.25 cm)
(0.23 cm)
(0.21 cm)
(0.18 cm)
Wire Line Lubricator Height Adjustment
Lubricator length should account for additional sinker bars allowing downward movement of the logging string.
Examples:
0.092" (2.3 cm) OD wire2000 psi WHP → 25 lbs min
(11 kg)
3/16" (.48 cm) OD braided wire2000 psi (13.8 mPa) WHP → 75 lbs min
(34 kg)
Note: Sinker bar weight given is at balance point. Add weight as desired to obtain downward movement.
Note: Sinker bar weight given is at balance point. Add weight as desired to obtain downward movement.
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Need team effort between operator and servicecontractor
Appropriate well pressure control equipment defined
Need company representative always on location
Need measurement checks with corrected depths
Agree on findings, write down, discuss, concur
Put together clues to develop answers
Issue recommendations from log findings
• Summaries of wellcompletion details
• Full productionhistory
• All open hole logs• PVT data
Forward planning will ensure maximum long term use of log data.
General Production Logging Guidelines
Agree on findings, write down, discuss, concur
Why the logging is undertaken Previous production-logging summary Current well-completion data with a wellbore sketch Collars used for perforation Depth reference point Most recent well-test data Anticipated total depth, bottom hole pressure, and temperature
A second form completed at the time of logging lists: Logs run and their order Run number String logged and its status for each run Status of other strings or annuli Logging direction and speed Tool calibration checks Intervals where re-runs were logged
A good rule is to prepare a preliminary summary that specifies:
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Production Logging devices are measuring parameters which do not provide immediate concrete answers to specific questions.
Information derived from one log is usually reinforced by another log. The assembly of all information generates the value of the final data.
Just like open hole logging tools, production logging tools should be run in complementing suites so that one log can be compared with another.
It is rare that a single log identifies a problem sufficiently to prescribe a remedial action.
Quality control is paramount, and careful attention must be focused upon three parts of the logging operation:
1. Procedure 2. Tool calibration3. Depth control
There are three pervasive myths about Production Logging:
Experience with specific devices in specific areas is an important factor for effective analysis.
1. Select the proper combination of tools.2. Establish a relevant operating procedure.3. Monitor data quality.4. Interpret results.
A production log can be run by anyone1
Only one logging tool is needed2
The answer (anomaly) will jump out from a casual scan of the log3
Misconceptions About Production Logging
NO !
NO !
NO !Through the next presentations, we will show how the diagnosis of individual well production issues is dependent on understanding tools characteristics, their selection and log interpretation.
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Blades Monitors wellbore condition (open or cased hole)
After a drilling phase, caliper data are integrated to determine the volume of the open hole
Caliper offers a qualitative indication of the condition of the wellbore and the degree to which the mud system has maintained hole stability
Very useful with any Production Logging run
The caliper measurement point corresponds exactly to the measurement point of the flowmeter impeller
Caliper
A B
Moving caliper
arm
or multi-finger types
Caliper tool: Variable resistance
Caliper arm
Variable resistor
Main Applications Limitations
1. Correct the flowmeter readings for diameter variations due to either heavily scaled tubulars or differences in open hole completions
2. Locate packer seats in open hole sections
3. Determine restrictions for future tubing or casing work (workover planning)
4. The caliper data can be used independently for determining general internal corrosion, paraffin buildup, or mineral scaling
• Normal two or four arm calipers will only give general indications of corrosion and other more sophisticated tools need to be run to examine the corrosion issues furtherCOPYRIG
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Blades Monitors wellbore condition (open or cased hole)
After a drilling phase, caliper data are integrated to determine the volume of the open hole
Caliper offers a qualitative indication of the condition of the wellbore and the degree to which the mud system has maintained hole stability
Very useful with any Production Logging run
The caliper measurement point corresponds exactly to the measurement point of the flowmeter impeller
Caliper
A B
Moving caliper
arm
or multi-finger types
Caliper tool: Variable resistance
Caliper arm
Variable resistor
Main Applications Limitations
1. Correct the flowmeter readings for diameter variations due to either heavily scaled tubulars or differences in open hole completions
2. Locate packer seats in open hole sections
3. Determine restrictions for future tubing or casing work (workover planning)
4. The caliper data can be used independently for determining general internal corrosion, paraffin buildup, or mineral scaling
• Normal two or four arm calipers will only give general indications of corrosion and other more sophisticated tools need to be run to examine the corrosion issues further
Multi-finger Calipers• Motorized Centralizers to ensure effective centering force
– Equipped with rollers to prevent casing and tubing damage
For cased hole logging, the caliper will give indications about: • Conditions inside the casing• Damage• Scale• Paraffin deposits
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Spectral Noise Logging (SNL) • Records acoustic noise generated by fluid or gas flow • Tool listens passively to downhole noise such as gas bubbling up
through liquid in the wellbore– Behind pipe, a channeling flow passes through “tight spots”, which
cause higher velocities, sudden pressure reductions and significant flow turbulence
– The noise-logging tool listens for noise associated with the turbulence
• The tool includes piezoelectric crystal transducers which convert the oscillating pressure of wellbore sound to corresponding oscillating voltage
– The oscillating voltage is applied to a speaker at the surface, as well as each of four high-pass filters
• Each high-pass filter detects nothing below its filter range• Log noise filters for 200, 600, 1000 & 2000 Hz• Two-phase flow occurs at about 200 to 600 Hz• High rate single phase flow occurs above 1000 Hz• Sound is highly attenuated by gas• Tool works best for low rate gas leaks
Noise Spectrum
200
600
1,000
2,000
Differential Pressure
Single phase
Two phase
Rel
ativ
e am
plit
ud
e
Frequency, hz
Rel
ativ
e am
plit
ud
e
Frequency, hz
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High noise amplitudes indicate locations where the flow path is submitted to turbulence
The noise log has been used as an indicator of channeling behind pipe
• Flow through channel is indicated on a noise log by the presence of high amplitude noise at places where restrictions in the channel causes throttling of fluid
Flow through a leak results in a pressure drop that generates detectable noise
Noise Log Principle
Piezoelectric Crystal
Microphone
2000
1000
600
200 HZ
5.7
14.1
27.3
55.0
Millivolts
High PassFiltersCOPYRIG
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Filter’s output consists of positive excursions from neutral alternating with negative excursions
Amplitude is measured two ways1. Measure from peak of positive excursions to trough of following
negative excursion– “Peak to peak” amplitude
– “Standard gain” or “Standard sensitivity” recording
2. Measure from the peak of a positive excursion to neutral– “Peak” amplitude
– “One-half standard gain” recording
Noise Log Principle
Piezoelectric Crystal
Microphone
2000
1000
600
200 HZ
5.7
14.1
27.3
55.0
Millivolts
High PassFilters
Filter’s output consists of positive excursions from neutral alternating with negative excursions
Amplitude is measured two ways1. Measure from peak of positive excursions to trough of following
negative excursion– “Peak to peak” amplitude
– “Standard gain” or “Standard sensitivity” recording
2. Measure from the peak of a positive excursion to neutral– “Peak” amplitude
– “One-half standard gain” recording
Measurements• A single station measurement lasts 3 to 4 minutes• Relocating the tool requires 1 minute• Thus, the logging rate is approximately 15 stations per hour, and
a 4-hour logging run accommodates 60 measurements• 30 measurements are used for a course-measurement grid, with
successive measurements separated by 1/30th of the total survey interval
• The remaining 30 measurements are used for detailing areas of interest
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In desert conditions, surface temperature may initially decrease, reach a neutral point, and then increase
The geothermal temperature profile varies significantly from area to area, and the slope of the geothermal temperature varies from formation to formation
COOKING LAKE
Example of Geothermal Gradient
Knowledge of the geothermal temperature profile is necessary for temperature log interpretation
• Record one baseline log within a well shut-in and stabilized, before production start-up
The geothermal gradient is generally assumed to be constant when interpreting temperature logs in a given area
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Production zones may or may not be clearly identified on a temperature log
When free gas is flowing from the reservoir, pressure drawdown will induce a significant cooling of the gas in the near-wellbore vicinity due to Joule-Thomson effect
• Gas entry locations are identified by cool anomalies on a temperature log
A
B
C GgradDTSProd-1RateRateCumRateCOPYRIG
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Record a full (top to bottom) reliable geothermal gradient log (base line log) during the first Production Logging run
Routine: stabilize rate for 48 hours, log, shut in for about 24 hours
Record temperature profiles, well shut-in, at repeated time intervals
Log down and up, make re-runs (after 1-2 hrs), check log response
Analyze temperature log versus flowmeter log
Temperature profiles can be used for flow rate estimation
Document results and recommendations
Remember: in high rate gas wells, with low compressibility, the Joule-Thomson effect may be reversed and create a local heating at the fluid entry point (molecular friction effect)
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The spinner flowmeter is the most commonly used device for measuring flow profiles, both in injection and production wells.
Impeller placed in well to measure fluidvelocity
• Signal period on output coil • Frequency of rotation F• Measures in rps
Characteristics• rps are filtered before recording• Spin direction is now presented on logs
Continuous Flowmeter Sonde (CFS)• Maximum Pressure (psi) 15000 (103 mPa)
• Maximum Temperature (°F) 350 (177 °C)
• Makeup Length (inches) 24.0 (61 cm)
Lower Bearing
Spinner
Pickup Coil
Upper Bearing
Electrical Connection Flowmeters must be centralized in the
wellbore so that accurate flow velocity of flow stream center can be determined
Use a caliper for accurate flowdetermination
To determine the minimum fluid velocityrequired for spinner to rotate:
1. Multiple up and down passes are madeand calibration chart is developed to determine fluid flow velocity and cable logging speed
2. Spinner velocity will be at fluid conditionsat the point of measurement and will need to be converted back to stock tank conditions during final calculations
Magnet
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Maximum Flow, bbl/d (m3/d) 1800 (286.2) 1000 (159)
Maximum Pressure (psi) 15000 (103 mPa)
Maximum Temperature (F) 350 (177 C)
Weight (lbs) Makeup Length (in) 60 (152 cm)
Maximum Flow (bbl/d)• Basket Open 2000 (318 m3/d)• Basket Closed 10000 (1589.9 m3/d)
Maximum Deviation () 60
Single phase (bbl/d) >100 (15.9 m3/d)
Qo in two phases (bbl/d) > 30 (4.8 m3/d)
Qw in two phases (bbl/d) >400 (63.6 m3/d)
Accuracy (%) 10
Exit Ports
Spinner
Hold-up Meter
Water Resistivity
Cell
DC Motor
The most accurate of the spinner devices when low total rates and multiphase flow occurs.
• Can detect flowrates as low as 10 to 15 bbl/d (1.6 to 2.4 m3/d).
– A typical 1-11/16-in (4.3 cm) tool has a barrel ID of approximately 1.45 in (3.9 cm).
– A flow of 10 bbl/d results in a velocity of 3.4 ft/min (1.04 m/min) inside the barrel.
– Because of the limited clearance between the spinner and the barrel, this velocity is enough to overcome friction and rotate the spinner.
– A flow of 100 B/D passes through the barrel at 34 ft/min (10.4 m/min) – enough to start the homogenization of the flow.
– In a casing, a rate of 2,000 bbl/d (318 m3/d)is needed to obtain the same effect around a continuous spinner.
– The tool can be calibrated directly for such flow.
Metal Petals
Small clearance between the spinner and the ID of the barrel assures almost no diversion of flow around the spinner.
As the spinner rotates, it generates a specific number of voltage pulses per revolution.
• The pulse rate from the tool can be transmitted through the logging cable for surface recording and determination of corresponding revolutions per second.
Typical basket flowmeters are rated for 320 – 350°F (160 – 177°C) temperatures and 15,000 to 20,000 psia (103 to 138 mPa).
Maximum Flow, bbl/d (m3/d) 1800 (286.2) 1000 (159)
Maximum Pressure (psi) 15000 (103 mPa)
Maximum Temperature (F) 350 (177 C)
Weight (lbs) Makeup Length (in) 60 (152 cm)
Maximum Flow (bbl/d)• Basket Open 2000 (318 m3/d)• Basket Closed 10000 (1589.9 m3/d)
Maximum Deviation () 60
Single phase (bbl/d) >100 (15.9 m3/d)
Qo in two phases (bbl/d) > 30 (4.8 m3/d)
Qw in two phases (bbl/d) >400 (63.6 m3/d)
Accuracy (%) 10
Exit Ports
Spinner
Hold-up Meter
Water Resistivity
Cell
DC Motor
The most accurate of the spinner devices when low total rates and multiphase flow occurs.
• Can detect flowrates as low as 10 to 15 bbl/d (1.6 to 2.4 m3/d).
– A typical 1-11/16-in (4.3 cm) tool has a barrel ID of approximately 1.45 in (3.9 cm).
– A flow of 10 bbl/d results in a velocity of 3.4 ft/min (1.04 m/min) inside the barrel.
– Because of the limited clearance between the spinner and the barrel, this velocity is enough to overcome friction and rotate the spinner.
– A flow of 100 B/D passes through the barrel at 34 ft/min (10.4 m/min) – enough to start the homogenization of the flow.
– In a casing, a rate of 2,000 bbl/d (318 m3/d)is needed to obtain the same effect around a continuous spinner.
– The tool can be calibrated directly for such flow.
Metal Petals
Small clearance between the spinner and the ID of the barrel assures almost no diversion of flow around the spinner.
As the spinner rotates, it generates a specific number of voltage pulses per revolution.
• The pulse rate from the tool can be transmitted through the logging cable for surface recording and determination of corresponding revolutions per second.
Typical basket flowmeters are rated for 320 – 350°F (160 – 177°C) temperatures and 15,000 to 20,000 psia (103 to 138 mPa).
Record stationary readings above and below perforations
Record repeat runs
The method is• Best for single-phase flow• Good for oil and water two-phase flow• Questionable under liquids and gas flow• Needs additional support (software, gauges, etc.) • Questionable for hole angles beyond 70°
Document all results
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Advances in downhole video equipment now offer thismeasurement as an alternative to the new class of productionlogging measurements.
A downhole video log is a means to directly identify location offluid entries into the well, because almost all production wellscontain water through which the hydrocarbons are passing.
High rate water entries can also be detected from the imagedistortion caused by high levels of turbulence.
This approach is qualitative and does not fully replace productionlogging tools.
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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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