Multi String Imaging EmPulse - TGT

www.tgtoil.com

Multi String Imaging

EmPulse

White Paper

Andrey Arbuzov, Maxim Volkov,

Sami El Halfawi and Arthur Aslanyan

June 2016

http://www.tgtoil.com/

EmPulse and SNL-HD are TGT’s patented or patent-pending technologies

www.tgtoil.com 2

Contents

1. Physics ......................................................................................................................... 3

1.1. TOOL OPERATING PRINCIPLE AND DESIGN ................................................................................................. 3 1.2. EMPULSE SENSORS .................................................................................................................................. 4

2. Numerical Model and Thickness Calculation ................................................................ 6

2.1. REAL TIME FITTING TECHNIQUE FOR THICKNESS CALCULATION ................................................................... 7 2.2. DELTA PANEL ....................................................................................................................................... 10

3. Laboratory experiments .............................................................................................. 12

3.1. SINGLE-BARRIER CASES ......................................................................................................................... 12 3.2. DUAL-BARRIER CASES ............................................................................................................................ 13 3.3. TRIPLE-BARRIER CASES.......................................................................................................................... 15 3.4. DUAL-STRING CASES .............................................................................................................................. 15 3.5. COLLAR CORROSION EVALUATION ........................................................................................................... 16

4. Well Data Processing and Interpretation .................................................................... 18

4.1. TEMPERATURE DATA CORRECTION ........................................................................................................... 18 4.2. AUTOMATIC COLLAR RECOGNITION ........................................................................................................... 18 4.3. TUBING CORROSION ............................................................................................................................... 19 4.4. CASING CORROSION INSPECTION THROUGH TUBING (2ND METAL BARRIER) ................................................. 21 4.5. SURFACE CASING CORROSION INSPECTION THROUGH TUBING AND PRODUCTION CASING

(3RD METAL BARRIER) ..................................................................................................................................... 21 4.6. INSPECTION OF DUAL-STRING COMPLETION .............................................................................................. 23 4.7. COLLAR CORROSION ............................................................................................................................... 23

5. Well Monitoring ........................................................................................................... 25

5.1. REPEATABILITY ....................................................................................................................................... 25 5.2. CORROSION PROPAGATION ..................................................................................................................... 26

Conclusions ....................................................................................................................... 27

Appendix A. EmPulse technical specifications ................................................................... 28



www.tgtoil.com 3

1. Physics

1.1. Tool Operating Principle and Design

The Magnetic Imaging Defectoscope EmPulse is a slim downhole tool designed to scan

metal around its sensors. The tools are run through the tubing to detect metal loss due to

corrosion or other factors and to monitor perforation quality.

The downhole EmPulse Defectoscope is currently represented by two modules:

EmPulse-2 for scanning the first two metal barriers of 2 7/8" to 13 3/8" size

EmPulse-3 for scanning up to 18 3/8" casing

Fig. 1. EmPulse-2 and EmPulse-3 modules

Combined toolstring contains three co-axial sensors of different lengths: the short 5" sensor

(EmPulse-2), the medium 13" sensor (EmPulse-2) and the long 19" sensor (EmPulse-3)

(see fig. 1). Each of these sensors is a generating-and-receiving electromagnetic coil wound

on a core. The receiving and generating coils are placed together to avoid ghost effects from

defects and well completion components. Those coils alternately generate electromagnetic

excitation pulses. The speed of decay of a response pulse is governed by the properties of

the tubing and casing surrounding the tool. Metal loss due to corrosion causes a faster

decay.

Fig. 2. Generating and receiving coils

5” Short sensor

13” Medium sensor

19” Long sensor

EmPulse-2 EmPulse-3



www.tgtoil.com 4

The short receiver coil records a short time response sampled in 42 channels, scanning the

near zone where only one barrier is present, which is normally a tubing string. The medium

coil generates a separate electromagnetic pulse and records a longer response sampled in

51 channels. The long coil records the longtime response sampled in 83 channels. That

coils scan a larger distance of up to 14 inches and up to 20” respectively and capture a

combined response from tubing and casings. Further mathematical processing enables the

identification of an independent casing response. As an example, fig. 3 shows excitation

pulse and decay of response pulse for medium sensor.

Fig. 3. Excitation pulse and decay of response for medium sensor

1.2. EmPulse Sensors

The response duration in vacuum defines the tool's dead time and depends on the relaxation

time of the coil. The faster the coil's relaxation, the faster the tool can detect an informative

response of the metal component.



www.tgtoil.com 5

The relaxation time of the EmPulse coil is approximately 0.1 ms, which is shorten than in

most of conventional defectoscopes. The last one can only start recording after 4 ms from

the start of the decay as it represents the response of the coil but not of the surveyed well.

As a result, the application of conventional defectoscopes is limited and scanning of chrome

pipes is challengeable because the time response of non-magnetic steel equals the typical

coil relaxation time of a conventional defectoscope. Moreover, information about the first

metal barrier will be partially lost.

Fig. 4. Responses detected by EmPulse (blue line) and conventional defectoscope (green line) in vacuum and EmPulse decays in the stainless (black line with red points) and in the ferromagnetic (black line with blue points) steel pipes.



www.tgtoil.com 6

2. Numerical Model and Thickness Calculation

The EmPulse simulator is a software used for calculating simulated decays of the tool and

the well. Comparison of simulated decays with actual responses enables the calculation of

wall thicknesses of the first, second, third and even fourth barriers independently (see

Section 2.1).

In fact, calculation of the system response to magnetic disturbance is reduced to calculation

of the magnetic field near the receiver coil. The electromagnetic field shape is described by

the following two Maxwell’s equations,

.0)(,)(

,)(,)(

Bdivt

DjHrot

Ddivt

BErot

(1)

Using additional constitutive relations and Ohm`s law:

(2)

The problem can be simplified to a homogeneous piecewise medium with coaxially

cylindrical boundary surfaces, and the receiving coil is mounted concentrically over a core.

It is assumed that electromagnetic parameters (electrical conductivity σ and magnetic

permeability μ) are constant within the same medium. The solutions of Maxwell’s equations

(1) in terms of frequency are reduced to iteration problems of field calculation in each

medium in such case.

Fig. 5. Axially symmetric model of a tripple-barrier completion

Note that response parameters (amplitude and decay time) are usually defined by geometric

parameters (radius and d – wall thickness) and electromagnetic parameters (μ and σ) of

casing and tubing pipes and depend on the parameters of other media. Therefore, decay

.,, 00 EjEDHB



www.tgtoil.com 7

time can be roughly represented as a d·μ·σ multiplication; the thicker the pipe wall, the

longer the response decay time.

2.1. Real Time Fitting technique for Thickness Calculation

Real Time Fitting (RTF) algorithm has been developed to determine the thicknesses of up

to four coaxial metal barriers. The calculation procedure can be divided into three stages:

Calculation of simulated responses for different parameters of the surrounding

medium;

Estimation of electromagnetic parameters of the surrounding medium;

Estimation of barrier thickness in relation to depth.

The response is a function of electrical conductivity σ, magnetic permeability μ and the

geometric parameters of the surrounding media. It is assumed that the response is entirely

determined by the metal completion components and is almost independent of the

surrounding rocks and fluid. This assumption is confirmed by the great difference between

the electromagnetic characteristics of metals, rocks and fluid. Therefore, electrical

conductivity, magnetic permeability and tubing/casing thickness are the only variables.

Other parameters are assumed to be constant.

The simulated decays are used to calculate tubing/casing parameters (μ and σ) and estimate

their thicknesses. The parameters are being fit to minimize the discrepancy between

simulated and measured responses. For more precise thickness estimation, the simulated

decays are interpolated with the μ and σ values. Then, simulated decays are selected for the

corresponding actual decays at each depth to produce tubing/casing thickness profiles, such

as those shown in fig. 6.

Fig. 6. Comparison of actual and simulated decays

It can be clearly seen in fig. 6 how pipe thickness affects decay time: changes in tubing

thickness affect the total signal, while a change in casing thickness only affects the total

signal at late times.

The example displayed in fig. 7 shows the application of the algorithm for calculating

thicknesses of both tubing and casing from the recorded data. Average tubing and casing



www.tgtoil.com 8

thicknesses appeared to be 7.8 mm (13.5 lb/ft) and 12 mm (47 lb/ft), respectively,

corresponding to the nominal pipe thicknesses. It can be seen that the tubing integrity is

good and casing corrosion can be seen at a depth of X118 ft.

Fig. 7. An example of thickness calculation for a two-barrier completion. Nominal thicknesses are shown as dashed lines.

Corrosion detection in multi-barrier wells is time-consuming, and data processing time

increases many-fold with the number of barriers. Thus, the number of modelled decays for

one well in the three-barrier case under study can reach hundreds of thousands. To reduce

the time of processing and interpreting data from a typical three-barrier well to several hours,

a new algorithm has been developed for a supercomputer that can operate remotely and

can be accessed from a normal computer through the Internet.

Fig. 8 presents findings acquired in a 9 5/8″ OD pipe having the wall gradually reduced in

thickness. The raw data distinctly show uniform metal loss. The casing thickness calculated

by the thickness calculation algorithm RTF corresponds strictly to the wall thickness

measured.

Similar results are demonstrated for a 3 ½’’ tubing with gradually reduced wall thickness on

fig. 9.



www.tgtoil.com 9

Fig. 8. Findings in a 9 ⅝″ pipe gradually reduced in size. From left to right: picture of the pipe, depth scale, pipe schematic, FAR RESPONSE 35 log (27.4 ms), calculated THICKNESS log.

Fig. 9. Findings in a 3 1/2″ pipe gradually reduced in size. From left to right: picture of the pipe, depth scale, pipe schematic, NEAR RESPONSE 27 log (8.66 ms), calculated THICKNESS log.



www.tgtoil.com 10

2.2. DELTA Panel

The EmPulse set of data can contain more than 176 channels: 42 short sensor logs + 51

medium sensor logs + 83 long sensor logs + logs from auxiliary gauges like temperature,

acceleration etc. It is impossible to visualise and analyse all of those logs simultaneously in

a conventional way. One can visualize logs as coloured DELTA panels, where y-axis is

depth, x-axis is time and colour is amplitude (blue – high amplitude, red – low amplitude).

The informative DELTA panel shows differences between simulated and real responses.

The difference between the Short Sensor recorded and simulated responses called SS

DELTA, for Medium Sensor – MS DELTA and for Long Sensor it is LS DELTA. This panel

provides sharper image contrast and shows metal losses in finer detail.

mod

mod

( ) ( )( )

( )

R el

el

U t U tt

U t

. (3)

Fig. 10. The DELTA panel – basics

The panel shows good match with the model in white and mismatches in colours (see, e.g. fig. 12-17).

The raw response greater than the simulated response is shown in blue. The underrated raw response

is shown in red. At all depths where well completion has a perfect axial-symmetric geometry, the

DELTA panel is white.



www.tgtoil.com 11

In most cases DELTA panel is white. In other cases, it develops a colour pattern at some

events, for e.g. tubing collars at X600 ft, X632 ft and X662 ft and casing collars at X612 ft

and X650 ft (see fig. 11).

Fig. 11. Colour DELTA panels

The coaxial model does not account for non-coaxial elements, such as tubing/casing holes,

valves, mandrels, perforations, etc, which all appear to be circularly smeared (azimuthally

averaged) and do not indicate real thicknesses.

For example, a 1-inch hole in 3 1/2-inch tubing is not axially symmetric. The coaxial model

does not understand this and reports 1% circumferential metal loss per foot (which is

equivalent in volumes to 1-inch hole in 3 1/2-inch tubing within the sensor length) and thus

can be easily overlooked in the thickness log. But the DELTA panel clearly shows that model

and raw responses do not match.

Note that DELTA panel has nothing to do with the amount of metal loss/gain. Thickness log is the only

curve which relates to the amount of metal loss/gain.

42

channels

51

channels

91

channels

Short

Sensor

Middle

Sensor

Long

Sensor



www.tgtoil.com 12

3. Laboratory experiments

The EmPulse tool sensitivity to different types of wall metal loss (holes, transverse and

longitudinal fractures) was studied using pipes with known dimensions and defects in the

laboratory. This section describes some of the results.

3.1. Single-Barrier Cases

A pipe with an outside diameter of 3 1/2" and a wall thickness of 5.2 mm was surveyed. Two

defects were made in the pipe: a 35-mm longitudinal slot and a 20-mm hole. Fig.12 shows

the survey results. The hole and the longitudinal slot displayed in the DELTA panels of both

the short (SS DELTA) and medium (MS DELTA) sensors as red areas at middle times (3.5–

17.8 ms). The defects are seen in the thickness log, but average metal loss, for example in

the case of a through hole, is only 0.2 mm. For that reason, small defects can be over looked

in the thickness log but will be clearly shown in the DELTA panels.

Fig. 12. The results of a single-barrier laboratory test: picture of the pipe, depth scale, pipe sketch, the DELTA panels of the short (SS DELTA) and medium (MS DELTA) sensors, calculated pipe wall thickness (3 1/2" TUBING Thickness 1) with nominal pipe wall thickness (dashed line)



www.tgtoil.com 13

Similar findings were recorded for a 2 7/8’’ tubing with flaws shaped as a vertical slot 38 mm

in length and a 38-mm square hole (fig. 13)

Fig. 13. The results of a single-barrier laboratory test: picture of the pipe, depth scale, pipe sketch, the DELTA panels of the short (SS DELTA) and medium (MS DELTA) sensors, calculated pipe wall thickness (2 7/8" TUBING Thickness 1) with nominal pipe wall thickness (dashed line)

3.2. Dual-Barrier Cases

A study of a dual-barrier completion was conducted with the following configuration: the first

pipe has a diameter of 3 1/2" and a wall thickness of 7 mm; the second pipe has a diameter

of 9 5/8" and a wall thickness of 9.5 mm. Two defects were made in the second pipe: a 125-

mm (5-inch) longitudinal slot and a hole of 80-mm (3-inch) diameter. Fig.14 shows the study

results. No defects are displayed in the short sensor panels. The defects are displayed in

MS DELTA panel of the medium sensor as a red area at late times (40–100 ms), marked by

casing corrosion line (CL2). The defects are also seen in the thickness log (see Fig. 14).



www.tgtoil.com 14

Fig. 14. The results of a dual-barrier laboratory test: pipe picture, depth scale, pipe sketch, the DELTA panels of the short (SS DELTA) and medium (MS DELTA) sensors, calculated pipe wall thickness of the first and second barriers (3 1/2" TUBING Thickness 1 and 9 5/8" CASING Thickness 2) with nominal pipe wall thickness (dashed lines).

Similar results were obtained for a dual-barrier completion: a 2 7/8’’ tubing with a collar and a 5 1/2’’ casing with a 90-mm square hole (Fig. 15)

Fig. 15. The results of a dual-barrier laboratory test: pipe picture, depth scale, pipe sketch, the DELTA panels

of the short (SS DELTA) and medium (MS DELTA) sensors, calculated pipe wall thickness of the first and

second barriers (2 7/8" TUBING Thickness 1 and 5 1/2" CASING Thickness 2) with nominal pipe wall thickness

(dashed line).



www.tgtoil.com 15

3.3. Triple-Barrier Cases

Fig. 16 shows the results of an EmPulse laboratory test performed to detect defects in the

third barrier. The testing unit simulated a typical well with three metal barriers: 3 1/2" tubing,

9 5/8" production casing and 13 3/8" intermediate casing. An artificial defect in the third

barrier, a 7 1/2" hole, simulated a homogeneous metal loss of 8.8% per foot of pipe. This

laboratory test conducted using the long 19" sensor of the EmPulse-3 tool confirmed the

defect (see the LS DELTA data panel in fig. 16). It is seen that the maximum deviation of

the recorded decay from the modelled one, shown as a red spot, occurred at the defect's

centre and was crossed by the CL3 corrosion line determined by modelling, which

demonstrates the accuracy of this technique. According to the simulation, the defect size

was equivalent to a metal loss of 6.8% per foot, i.e. within 2% error relative to an actual

value of 8.8%.

This lab test illustrates that the tested algorithm could provide accurate metal loss estimates

and confirmed the accuracy of the barrier thickness calculation

Fig. 16. The results of a triple-barrier laboratory test: depth scale, the pipe sketch, the DELTA panel of the

long sensor (LS DELTA), calculated pipe wall thickness of the first, second and third barriers (3 1/2" TUBING

Thickness 1, 9 5/8" CASING Thickness 2, 13 3/8" CASING Thickness 3) with nominal pipe wall thickness

(dashed line)

3.4. Dual-String Cases

Described below laboratory test was conducted to examine the performance of the EmPulse

technique in calculating the thickness of the third barrier for wells with parallel tubing strings.

For this purpose, the test unit was equipped with two inner 3 1/2" pipes, I and II, and two

Metal loss detected in

13 3/8” Casing

6.8%



www.tgtoil.com 16

outer 9 5/8" and 13 3/8" pipes. An artificial defect, a 7 1/2" hole, was made in the third barrier

to simulate a homogeneous metal loss of 8.8% per foot (see fig. 17).

The defect in this 13 3/8" pipe appeared in the LS DELTA data panel and was intersected

by the CL3 corrosion line. Metal loss was calculated at 7.1% per foot of pipe, which agreed

well with an actual value of 8.8% per foot.

It should be noted that this defect in the third barrier did not affect thickness calculations for

the second barrier and inner pipes. This primarily indicates that the tested modelling-based

thickness algorithm performs well even for dual-string wells

Fig. 17. The results of a triple-barrier with dual-string laboratory test: depth scale, the pipe sketch, the DELTA

panel of the long sensor (LS DELTA), calculated pipe wall thickness of the first, second and third barriers (3

1/2" TUBING Thickness 1, 9 5/8" CASING Thickness 2, 13 3/8" CASING Thickness 3) with nominal pipe

wall thickness (dashed line)

3.5. Collar Corrosion Evaluation

EmPulse technique allows an estimation of collar joint corrosion. The 4 1/2” tubing with walls

6.2 mm thick was subjected to inspection. Holes 0.5” in size were drilled around the collar

joint. Fig. 18 depicts logs of the short sensor for different corrosion degrees of the collar

joint. As shown in fig. 18, the amplitude of corroded collar is less than the amplitude of non-

corroded one.

7.1%

Metal loss detected in

the 3rd barrier



www.tgtoil.com 17

Fig. 18. The results of a collar corrosion laboratory test: depth scale, pipe sketch, and raw logs for different corrosion degrees of the collar joint.



www.tgtoil.com 18

4. Well Data Processing and Interpretation

Processing and data interpretation of EmPulse data are performed in special software that

implements EmPulse technique algorithms and includes many features to provide Clients

with high-quality row data and final interpretation reports within short time period. This

chapter describes some specific abilities while data processing and interpretation

4.1. Temperature data correction

The response amplitude of the same metal pipe can be different that is can be caused by

temperature variations. The temperature effect on the data should be accounted.

Empulse tools are equipped with temperature sensor and software filters applied allows to

eliminate temperature impact. Fig. 19 shows results of temperature correction. As it can be

observed, response deviation caused by temperature rise is removed.

Fig. 19. Temperature correction. Logs in red are before correction, logs in blue – after.

It is worth to mention, that temperature influence reduces on the logs for channels with later

times.

4.2. Automatic collar recognition

Increase of metal thickness caused by collar joint significantly enlarges a duration of

response decay. As a result, collars are reflected on channel logs as high-amplitude peaks.

Tubing collars forming first barrier can be nearly always identified as it can be observed in



www.tgtoil.com 19

fig.20. Casing collars of second barrier can be revealed on the logs for channels with later

times.

Automatic collar recognition algorithm allows to define tubing and casing collars with

accuracy of 1% and 5% respectively

Fig. 20. Automatic collar recognition for tubing (blue points) and for casing (green points)

4.3. Tubing Corrosion

Heavy corrosion of the tubing that has created a hole is displayed in the NEAR DELTA panel

in red (see Fig. 21). This is because the corrosion response is of higher amplitude at early

times and of lower amplitude at late times – since smaller amounts of metal allow rapid

signal changing, i.e. corrosion response increases and then decreases sharply – as shown

in an inlay plot in fig.21.



www.tgtoil.com 20

Fig. 21. Tubing corrosion



www.tgtoil.com 21

4.4. Casing Corrosion inspection through tubing (2nd metal barrier)

Casing corrosion detected through the tubing is not displayed in the NEAR DELTA panel,

but is displayed in the FAR DELTA panel at late times in red due to its lower amplitude (see

fig. 22). Corrosion is also seen in the thickness log. The spectral noise captured the noise

from channelling and entering the annulus at a corrosion zone of 17% metal loss suggesting

an integrity problem.

Fig. 22. Casing corrosion detected through tubing and confirmed by Spectrum noise logging.

4.5. Surface casing corrosion inspection through tubing and production

casing (3rd metal barrier)

9 5/8” and 13 3/8” casings corrosion zones of 52% and 73% metal loss accordingly were

detected downhole through the tubing and were confirmed by a surface visual inspection.

The corrosion behaviour suggests the external corrosion development due to poor

cementing and aggressive influence of sea water at a splash zone.



www.tgtoil.com 22

Fig. 23. Severe Corrosion detected in 9 5/8” and 13 3/8” casings at the splash zone depth in offshore oil producer.



www.tgtoil.com 23

4.6. Inspection of dual-string completion

In general, processing of EmPulse data for dual-string completions is the same as for single

tubing configuration. The presence of second tubing can slightly increase decay time that

should be taken into account while interpretation. Fig. 23 shows the corrosion identified in

second barrier in triple-barrier dual-string completion.

Fig. 24. Casing corrosion in double-string completion

4.7. Collar corrosion

Fig. 25 shows an EmPulse tool-detected corrosion of a collar joint at X592 m with a 53%

corrosion degree. PLT data, along with water holdup, density and high precision temperature

data, reveal inflow from the leaking tubing collar. The result proves that this is a through

corrosion of that collar.

9 5/8” Collar

3 1/2” SS Collar

13 3/8” Collar

13 3/8” Collar

3 1/2” LS Collar

Corrosion Zone

15%



www.tgtoil.com 24

Fig. 25. Corroded tubing collar confirmed by production logging tool.



www.tgtoil.com 25

5. Well Monitoring

Corrosion in wells develops over time and affects both their performance and operating

safety. Time-lapse corrosion monitoring data are used to improve pipe material selection

and enhance downhole inhibitors, as well as to find out the causes of corrosion and

understand its mechanisms. Systematic corrosion monitoring minimizes workovers and

extends the life of a completion string and, therefore, improves well and field economics.

This chapter shows that the EmPulse technology can detect corrosion at an early stage.

5.1. Repeatability

The EmPulse technology provides a high signal-to-noise ratio, which makes EmPulse logs

highly repeatable. Fig. 26 shows time lapse analysis of logs of the short and medium sensors

recorded by two EmPulse surveys in one well in 2009 and 2010. After automatic depth data

matching, the two logs appear to be virtually identical even at late times when the signal

decays significantly.

Fig. 26. The 2009 and 2010 logs recorded by the short and long sensors



www.tgtoil.com 26

5.2. Corrosion Propagation

Fig. 27 shows the corrosion development in the tubing of high rate oil-producer with a

relatively high H2S of more than 10%. Because of the high flow rate, H2S content and

possibility of corrosion, the decision was made to conduct a baseline metal loss survey and

another survey a year later.

Two EmPulse surveys were conducted to monitor metal loss in the 3-½", 9-5/8" and 13-3/8"

casings: the first survey in 2015 and the second one a year later in 2016. The first survey

was conducted in the newly set strings of a well that was just put on production, and its

results were used as baseline data to highlight the API thickness tolerated joints and to

improve the accuracy of metal-loss determination.

The second survey, conducted a year later, showed no metal loss in both tubing and casing.

This finding suggested good inhibitor selection by the Customer. The 3-½" tubing also

showed good data repeatability in most of the surveyed interval, but three joints lost more

than 20% of metal (see the fig. 27), which indicated problems with the tubing material.

Fig. 27. Corrosion propagation: depth scale, well sketches, the 2009 (red line) and 2010 (blue line) logs recorded by the short sensor, and the NEAR VARIATION colour panel

Based on the survey results, the Customer implemented a time-lapse monitoring plan in the

field to gather information on casing corrosion and monitor inhibitor performance. They also

analysed and changed the tubing metallurgy to avoid premature workovers.

It can thus be concluded that well monitoring significantly improves EmPulse data

interpretation. As a result, even a slight corrosion can be easily detected.

27 % metal loss in 3 ½”

TBG



www.tgtoil.com 27

Conclusions

The key advantages of the magnetic imaging defectoscopy EmPulse presented in this paper

can be summarised as follows.

1. The EmPulse tool containing three sensitive sensors records responses in a wide time

range digitized by 178 channels. Those characteristics allow the analysis of non-

magnetic chrome alloy steel pipes and detection of corrosion at an early stage.

2. Analysis of the decay pattern in a wide time range can determine metal thickness at

various distances from the tool and, thus, the individual wall thicknesses of the first,

second, third and fourth metal barriers, such as tubing and casings including dual-string

completions.

3. Algorithms developed for EmPulse data processing enable reliable identification of all

completion components as well as automatic location of collars in the barriers. The

software allows fast and reliable interpretation of large well data sets.

4. This technology has been tried and tested in laboratory studies, customer yard tests and

field tests and was proven effective in well data analysis.

5. Good repeatability of data and low data noise together with automatic data correlation

algorithms open up new possibilities for well monitoring using the magnetic imaging

defectoscopes EmPulse.



www.tgtoil.com 28

Appendix A. EmPulse technical specifications

Pressure rating 14 500 psi (100 MPa)

Temperature rating 302 °F (150 °C)

H2S < 30%*

Maximum wall thickness of single barrier 0.6 in (16 mm)

Maximum total wall thickness of dual barriers 1 in (25 mm)

Maximum total wall thickness of triple barriers 1.5 in (38 mm)

Barrier thickness accuracy

First barrier

±3.5% (±0.01 in or ±0.25 mm for

3 1/2’’ tubing with 7 mm wall

thickness)

Second barrier

±6% (±0.03 in or ±0.75 mm for

9 5/8’’ casing with 12 mm wall

thickness)

Third barrier

±12% (±0.06 in or ±1.5 mm for


thickness)

Fourth Barrier

±30% (±0.14 in or ±3.6 mm for


thickness)

Pipe OD range (1st barrier) 2 – 18 5/8 in

Pipe OD range (2nd barrier) 4 1/2 – 18 5/8 in

Pipe OD range (3nd barrier) 7 – 18 5/8 in

Maximum continuous recording time 48 hrs

Recommended logging speed 6.6-19.7 ft/min (2-6 m/min)

OD 1 11/16 in (42 mm)

Length 11.5** ft (3.5** m)

Weight 41** lb (18.5** kg)

* In wells with H2S concentration up to 30%, if O-Rings TFE/P L 1003 (Aflas) Black Duro 90 are

installed.

All materials used in the external parts meet the requirements of NACE TM 0177-2005 and NACE

TM 0284-2011.

** With RC-3 centralisers (2 pcs)


Multi String Imaging EmPulse - TGT

Documents

Transcript of Multi String Imaging EmPulse - TGT