Tubing Failure Analysis of Well Lohali#1 - Oil India _2015.pdf · 2015. 6. 22. · Tubing Failure...

Tubing Failure Analysis of Well Lohali#1 Chemical Note No.-92

Abstract

Severe tubing corrosion was observed in Well Lohali #1 which was taken up for

workover operation for carrying out a gravel packing job in the first week of July 2014.

The case of tubing corrosion and failure was taken up for study to ascertain the

corrosion phenomena and investigate the tubing failure and suggest remedial measure.

As a part of the investigation, the study of well history and laboratory analysis data for

the water, gas and condensate chemistry, metallurgical tests on the failed tubing,

corrosion product assay by XRD & EDS, SEM analysis of fracture surface features was

carried out for assessing the susceptibility of the material currently in use towards

corrosion . Corrosion rate determination was also carried out in simulated well

conditions of temperature , pressure , flowrate and corrosive environment in HPHT

Autoclave to substantiate the findings of the study.

The comprehensive failure analysis indicates a combination of localized pitting

corrosion due to carbon dioxide and moisture coupled with erosion corrosion due to

high flow rate and sand impingement in the deviated section of the well.

In order to mitigate and control the corrosion problem in wells in the same reservoir,

it is recommended to use alloys having better resistance to corrosion, redesign the

system to reduce flow velocity and running of Multi finger Imaging Tool(MIT) on a

periodic basis to get an idea about probable thickness reduction of the tubing.

ii


Contents

Abstract ............................................................................................................................................................. i

List of figures ................................................................................................................................................. iii

List of Tables ................................................................................................................................................. iv

1 Background........................................................................................................................................ 1

2 Introduction ...................................................................................................................................... 1

3 Material and methods .................................................................................................................... 2

4 Well History ....................................................................................................................................... 2

5 Brief on failure of gas tubular ..................................................................................................... 5

6 Visual Inspection of the failed tubing ...................................................................................... 5

7 Chemical test results ...................................................................................................................... 7

8 Material Integrity tests .................................................................................................................. 9

9 Energy Dispersive Spectroscopy(EDS) Test ...................................................................... 11

10 Scanning Electron Microscopy(SEM) of failed tubing .................................................... 13

11 Corrosion tests using Autoclave ............................................................................................. 14

12 Results and Discussion ............................................................................................................... 15

12.1 Water wetting ....................................................................................................................... 15

12.2 CO2 Corrosion ........................................................................................................................ 16

12.3 Erosion Corrosion ............................................................................................................... 16

13 Analysis of wells completed in NHK285 block. ................................................................ 17

14 Conclusions ..................................................................................................................................... 18

15 Recommendations ....................................................................................................................... 18

16 Acknowledgement ....................................................................................................................... 19

17 Bibliography ................................................................................................................................... 20

iii


List of figures

Fig 1: Well diagram Lohali# 1 (Deviated), Loc. HOB ...................................................................... 3

Fig 2: Well Profile showing kick off and casing shoe depth ......................................................... 4

Fig3: Course of the hole(Deviated section) ........................................................................................ 4

Fig 4: Failed tubing portion with deposits on the outside ............................................................ 6

Fig 5: Puncture on the tubing showing thinned out edges from inside to outside ............. 6

Fig 6: Parted portion of the failed tubing ............................................................................................ 6

Fig 7: Internal view of the parted tubing piece showing corrosion deposits ........................ 6

Fig 8: Punctures on another piece of corroded tubing .................................................................. 6

Fig 9: Failed tubing piece showing evidence of cracking along puncture .............................. 6

Fig 10: SEM of N-80 tubing at ID ......................................................................................................... 11

Fig 11: EDS of N-80 tubing at ID .......................................................................................................... 11

Fig12: SEM of N-80 Tubing after metallography ........................................................................... 12

Fig13: EDS of N-80 tubing after metallography............................................................................. 12

Fig 14: SEM showing pits and corrosion product ......................................................................... 13

Fig 15: SEM showing 294.12micron pit with streaks ................................................................. 13

Fig 16: SEM showing mesa attack ....................................................................................................... 13

Fig 17: SEM showing pits within pit. .................................................................................................. 13

Fig 18: Typical signs of erosion corrosion ....................................................................................... 17

Fig 19: Eroded tubing of Lohali#1 showing streaks .................................................................... 17

iv


List of Tables

Table 1: Gas tubular data ........................................................................................................................... 5

Table 2: Formation water analysis ........................................................................................................ 7

Table 3: Gas analysis Lohali#1 ................................................................................................................ 8

Table 4: Gas Analysis NHK613, NHK552, NHK609, NHK602 ...................................................... 9

Table 5: Chemical Analysis by Optical Emission Spectrometer Method( ASTM E-415-08,

IS 8811-98) .................................................................................................................................................. 10

Table 6: Tensile Test(Test Method- API-5CT) ................................................................................ 10

Table 7: Flattening Test (Test Method-ASTMA-370-2010) ...................................................... 10

Table 8: Brinell Hardness Test (Test Method-ASTME-10-2012) ............................................ 11

Table 9: Elemental analysis of the N-80 tubing at internal diameter .................................. 12

Table 10: Elemental analysis of the N-80 tubing at internal diameter after

metallography. ............................................................................................................................................ 12

Table 11: Corrosion rate with different grades of steel ............................................................. 14

Page | 1


1 Background

Severe tubing corrosion was observed in Well Lohali#1,which was taken up for

workover operation for carrying out a gravel packing job in the first week of July 2014.

The case of tubing corrosion and failure was referred by GM(G&R) vide letter ref no.

GM:GFD/01 dated 17.07.2014 to GM(Chemical) and Head (R&D) to ascertain the

corrosion phenomena and investigate the tubing failure.

In response, GM (Chemical) constituted a team vide letter ref. no.

Chem:5/4(O)/DB/2014 dated 21.07.2014. The team comprising of following members

from Chemical, R&D, G&R and Production (Gas) Departments was entrusted with the

responsibility for studying and investigating the tubing corrosion of Lohali#1:

a) Ms. Debajani Bose, Head-Chemical(P&A), Team Leader

b) Subodh Purohit, Dy. Suptg. Research Scientist, Team Coordinator

c) Surajit Das, Dy. Suptg.Chemist (Chemical), Team Member

d) Dilowar Hussain Laskar, Dy.SE(Prod-gas), Team Member

e) Jitendra Kumar, Sr. Reservoir Engineer, Team Member

This note covers the well history, failure description, the various laboratory tests

carried out in details and the findings thereof along with the recommendation for

avoiding similar incidences in other wells from the same reservoir.

2 Introduction

Corrosion is the destructive attack of a material by reaction with its environment and

is a natural potential hazard associated with oil and gas production and transportation

facilities. In the case of oil & gas wells, flowlines and pipelines, such highly corrosive

media are carbon dioxide (CO2), hydrogen sulfide (H2S), microbial activity and free

water .[1] Continual extraction of hydrocarbons associated with CO2, H2S, and free water

can over time make the internal surfaces of downhole tubing and components suffer

from corrosion effects. The downhole tubings and the component fittings of the oil and

gas wells undergo material degradations with the varying conditions of the well due to

changes in fluid compositions, souring of wells over the period, and changes in

operating conditions of the pressures and temperatures. This material degradation

results in the loss of mechanical properties like strength, ductility, impact strength, and

so on. This leads to loss of materials, reduction in thickness, and at times ultimate and

sudden failure. The serious consequences of the corrosion process have become a

problem of world wide significance.[2]

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3 Material and methods

In the case of well Lohali#1, the failed tubing showed visible signs of severe pitting

corrosion and cracks (Page No 6) . Accordingly, it was decided to carry out review of

well history (operational and workover), visual inspection of failed pieces, detailed

laboratory analysis for the water, gas and condensate chemistry, metallurgical tests on

the failed tubing, Optical Emission Spectrometry to determine chemical composition of

the metal substrate, corrosion product assay by XRD & EDS, SEM analysis of fracture

surface features and assessment of the susceptibility of the material currently in use

towards corrosion in simulated well conditions in high pressure high temperature

Autoclave.

4 Well History

This well was drilled in Feb 2002 and on testing the 3821 m , 3799 m and 3772 m

Lk+Th sands , the formations produced mainly water . The higher up 3754 m Lk+Th

sand was produced through well head set up @20-42 klpd (with 3-4% oil) through 6

mm bean with negligible FTHP. The well was kept shut in since Apr 2002. In 2009 the

3754 m Lk+Th sand was tested through live condition perforation but it produced

100% water. All these sands were plugged back.

The well was perforated in the range 2458 – 2464 m after cutting and recovering

5.1/2” casing (9.5/8” Casing shoe: 3103.37 m) and killing the well with 70 pcf Sodium

Formate. The well produced @ 1,15,000 SCMD gas with 25 klpd condensate and was

on continuous production since then. Before workover, the well was producing @

90000 scumd gas and condensate @ 10 klpd condensate with 6.3% water cut.

In view of the sand ingression problem being encountered since 2012 in the well, it

was decided to recomplete the well in the same formation (2438-Barail sand) with

gravel pack with 3.1/2" OD completion string). Wells in Lohali-Deohal area contains

gas with about 1.7-1.8% carbon-di-oxide. Presence of sulphur has not been measured.

The well was taken for workover operation. On 01/07/2014, after pumping around

338 bbl of 2% KCl solution as kill fluid through casing, no fluid return was observed

through tubing and the subsequent THP and CHP were observed to be nil.

Subsequently, X-Mass tree was rigged down and BOP was rigged up to facilitate

unsetting of Production Packer. The packer was unset with vertical pull of 82,000 Ibs.

But after pulling approximately 6 m of tubing out of the hole, the string weight

suddenly dropped to 17,000 Ibs indicating a rupture of tubing. It was eventually

Page 3


observed that tubing got parted off at 1094 m depth and the remaining part of tubing

fell into well sump as fish. Thereafter, fish recovery job was carried out on 04/07/2014

wherein the parted portion of tubing that remained inside hole was recovered at

surface. After recovering the tubing, it was found that tubings were severely corroded

and were having several holes.

Fig 1: Well diagram Lohali# 1 (Deviated), Loc. HOB

Fig1 above shows the well diagram. The detail well history is given in Annexure-I

(attached, page 21& 22). Fig2 and Fig3 (on page 4) below shows the well profile and

Page 4


the course of the deviated hole respectively. From the detail well history, it is observed

that the well was initially completed as an oil well and was kept shut in on two

occasions for prolonged period of time i.e. April 2002 to May 2009 (7 years) and July

2009 to September 2010 (1 year).

Thereafter, the well was tested for higher up sands and it was put on production of gas

along with condensate. During shut in periods, normally, carbon steel if left

uninhibited tends to develop general corrosion. General corrosion is aided by

deposition of the solids or scales.[3]

Fig 2: Well Profile showing kick off and casing shoe depth

Fig3: Course of the hole(Deviated section)

20” casing shoe @ 150 m

13.3/8” casing shoe @ 1200 m

9.5/8” casing shoe @ 3100 m

5.1/2” casing shoe @ 3960 m

Kick off point @ 164 m THD = 176.7m @ 1090 m

Maximum Drift Angle = 190 @

767 m Dev. Correction = 20.71 m

Page 5


Such corrosion effects are clearly visible on both the outside (Fig5) and inside ( Fig7)

on page 6 of the retrieved tubing singles. In addition, the failure zone occurred at the

deviated section of the well, where the chances of liquid impingement (condensate and

water) along with abrasive sands is maximum. This has further aggravated the

corrosion phenomenon leading to rupture of the tubing while it was being pulled out.

(Fig 4 to Fig 9 on page 6) shows different pieces of corroded tubing retrieved after the

workover operation.

5 Brief on failure of gas tubular

Table 1: Gas tubular data

6 Visual Inspection of the failed tubing

Field visit during workover operation revealed several holes of varying sizes in the

tubing above 1094m. The tubing below the parting depth did not show similar

occurrences of hole in the tubing (Fig7 on page 6). Instead, the wall thickness of the

tubing appeared to have reduced by 35 – 45% on an average, thinning out on the

periphery towards the orientation of the flow at the parting depth. The inside surface

of the parted tubing piece gives an impression of corrosion arising from erosion (as is

evident from the streaks on the inside surface. This may be due to very high flow of gas

through the 2.7/8” tubing where the condensate particles had an impinging effect on

the inside wall of the tubing thereby causing erosion corrosion.

Sl.No.

Parameter Details

1. Material specification N-80 Carbon steel 2. Date of commissioning. Feb 2002 3. Date of tubing snapping during workover. 02.07.2014 4. Tubing size 2.7/8”OD 5 Internal Diameter 62mm 6 Weight 6.5ppf 7 Sand Barail(2438m) 8 Gas flow rate 90000SCMD 9 Oil flow rate 55BOPD 10 Water flow rate 3.15Bbls/day 11 Water cut 0.8-6.3% 12 Kick off point 164m 13 CO2 content of flowing gas 1.84%(v/v) 14 Operating pressure FTHP=2450psi,FBHP=222.5ksc 15 Temperature FBHT=64.5˚C

Page 6


Fig 4: Failed tubing portion with deposits on the outside

Fig 5: Puncture on the tubing showing thinned out edges from inside to outside

Fig 6: Parted portion of the failed tubing

Fig 7: Internal view of the parted tubing piece showing corrosion deposits

Fig 8: Punctures on another piece of corroded tubing

Fig 9: Failed tubing piece showing evidence of cracking along puncture

Page 7


7 Chemical test results

The detailed analysis of formation water of Lohali#1 was carried out and the results

obtained are given inTable2 (below).The sample was collected on 12.09.2014

Table 2: Formation water analysis

Literature reveals that the risk of corrosion is negligible if the Ca++/HCO3- ratio is less

than 0.1, but for sample 1 the Ca++/HCO3- ratio is 0.04. This indicates lower corrosivity

of produced water. High concentration of bicarbonate produce a buffering effect which

reduces corrosivity even when carbon dioxide partial pressure is fairly high. However,

high concentration of chloride ion present in the sample1 could promote breakdown of

protective films leading to pitting corrosion . This was clearly evident from the visual

inspection of the failed tubing and is visible in the photograph of corroded tubing given

in page 6. For wells prone to corrosion, monitoring of critical parameters responsible

for corrosion is essential to deal with the menace of corrosion .

Parameters Unit Sample1

Appearence mg/l Turbid

Calcium mg/l 99.1

Sodium mg/l 2541.1

Magnesium mg/l 42.2

Manganese mg/l 2.1592

Iron as Fe+2 mg/l 5.5132

Chloride mg/l 3124

Sulphide mg/l 0.002

Sulphate mg/l 117.86

Hydroxide mg/l nil

Carbonate mg/l nil

Potassium mg/l 2541.3

Acetates mg/l nil

Bicarbonate mg/l 2440

Formate mg/l 2048.5

Page 8


Corrosion rate calculated in HPHT Autoclave by gravimetric analysis indicates high

corrosion of flowing fluid under simulated conditions of pressure and

temperature(1600psi with 30 psi CO2 partial pressure and 45˚C). Visual inspection of

tubing also indicated severe deterioration of tubing material.

The Chromatographic analysis of gas samples collected from Lohali#1 was carried out .

Sample 1 was collected prior to tubing failure and sample 2 was collected after

completion of gravel pack job in Lohali#1. The results obtained are given in Table 3

(below). The gas samples were collected on 08.05.2014 and 26.11.2014 respectively.

Table 3: Gas analysis Lohali#1

The above table shows the percentage fraction of various gases present in the gas

samples collected from Lohali#1. Carbon dioxide concentration was found to be 1.8%

and 2.26% in sample1 and sample2 respectively. This Carbon dioxide concentration

corresponds to a partial pressure of 30psi and 36psi respectively for simulating the

well conditions while tested in HPHT Autoclave.

Components Composition Sample1 Sample2

Methane %v/v 91.90 90.31

Ethane %v/v 4.90 4.95

Propane %v/v 0.26 0.32

i-Butane %v/v 0.33 0.52

n-Butane %v/v 0.11 0.22

i-Pentane %v/v 0.12 0.41

n-Pentane %v/v 0.06 0.21

Hexane+ %v/v 0.41 0.52

Nitrogen %v/v 0.07 0.28

Carbon Dioxide %v/v 1.84 2.26

Oxygen %v/v 0.00 0.00

Page 9


In gas wells with a pH of 7 or less a CO2 partial pressure of 30psi usually indicates

corrosion. The chromatographic analysis of gas from other producing wells of same

reservoir are given in Table4 (below)

Table 4: Gas Analysis NHK613, NHK552, NHK609, NHK602

The above table indicates the presence of carbon dioxide in all the current producing

wells of the same reservoir. Since carbon dioxide is one of the major factor

contributing to corrosion in gas condensate wells, it is obvious that all the wells

namely NHK613, NHK552, NHK609 and NHK602 are susceptible to carbon dioxide

corrosion.

8 Material Integrity tests

The necessary laboratory tests on metal samples of the failed tubing was outsourced to

M/s TCR Advanced Engineering Private Limited, Vadodara to ascertain the root cause

of failure and to take remedial actions in the future. The following material integrity

tests were carried out at TCR Advanced Engineering Private Limited.

1. Chemical analysis by optical emission spectroscopy.

2. Mechanical tests such as Tensile test , Flattening test and Hardness test.

Components Composition NHK613 NHK552 NHK609 NHK602

Methane %v/v 89.36 83.16 88.50 89.82

Ethane %v/v 5.59 6.79 5.63 5.68

Propane %v/v 0.89 2.19 1.24 0.86

i-Butane %v/v 0.59 0.90 0.64 0.59

n-Butane %v/v 0.41 0.97 0.55 0.40

i-Pentane %v/v 0.3 0.51 0.34 0.30

n-Pentane %v/v 0.16 0.29 0.19 0.16

Hexane+ %v/v 0.24 2.60 0.22 0.22

Nitrogen %v/v 0.99 0.91 1.07 0.33

Carbon Dioxide %v/v 1.47 1.68 1.62 1.64

Oxygen %v/v 0.00 0.00 0.00 0.00

Page 10


The results of Optical emission spectroscopy and Tensile stress are given below in

Table 5 and Table 6

Table 5: Chemical Analysis by Optical Emission Spectrometer Method( ASTM E-415-08, IS 8811-98)

ELEMENT OBSERVED REQUIRED Carbon(%) 0.282 Sulphur(%) 0.00860 0.030Max Silicon(%) 0.326 Phosphorous(%) 0.0200 0.030Max Manganese(%) 1.34 Chromium(%) 0.435 Nickel(%) 0.0250 Aluminium(%) 0.0270 Copper(%) 0.0160

Table 6: Tensile Test(Test Method- API-5CT)

OBSERVED REQUIRED Width (mm) 12.63 - Thickness (mm) 5.62 - Area (mm2) 70.98 - 0.2% Proof Load (N) 45113 - UTS(N/mm2) 724 689min % Elongation 16.60 13 min Fracture Near 2/3 WGL

The above two tests indicated that the failed tubing material meets the requirements of

API 5CT Gr N80 with respect to elements analysed and tensile strength.

The results of Flattening test is given below in Table7. The Hardness test results are

given in Table 8 (page11).

Table 7: Flattening Test (Test Method-ASTMA-370-2010)

Outer Diameter (mm) 73.18 Thickness (mm) 5.75 Constant E (mm) 0.07 carbon steel H Value 41.41 /DISP: 31.77 Observation No Cracks Observed

Page 11


Table 8: Brinell Hardness Test (Test Method-ASTME-10-2012)

Location Hardness Reading in "BHN" at 187.5 kg Load

At Core 230, 230, 229 (230 HBW/2.5/187.5)

The Brinell hardness corresponding to ultimate tensile strength value of 724 N/mm2 is 222 BHN. The observed BHN is 230. Therefore the material meets the specification of API 5CT GrN-80 tubing.

9 Energy Dispersive Spectroscopy(EDS) Test

Energy Dispersive Spectroscopy (EDS) of the failed tubing was carried out at the

internal surface of the failed tubing before and after metallography to determine the

elemental composition of the tubing. The results so obtained are tabulated in Table 9

and 10 ( Page12). Fig10 and Fig 11(below) shows the Scanning Electron Microscope

image and EDS spectrum of N-80 tubing sample before metallography. Similarly Fig 12

and Fig 13 (page12) shows the Scanning Electron Microscope image and EDS spectrum

of N-80 tubing sample at internal diameter after metallography.

Scanning Electron microscopy reveals pitting corrosion which is localized in nature.

Fig 10, above shows the initiation of pits against the thickness of metal.

Fig 10: SEM of N-80 tubing at ID

Fig 11: EDS of N-80 tubing at ID

Page 12


Table 9: Elemental analysis of the N-80 tubing at internal diameter

Table 10: Elemental analysis of the N-80 tubing at internal diameter after metallography.

Fig12: SEM of N-80 Tubing after metallography

Fig13: EDS of N-80 tubing after metallography.

The presence of high levels of oxygen concentration from EDS study above (Table 9 &

Table 10), confirms the presence of iron oxide which is an indication of the presence of

corrosion products inside the tubings.

ELEMENTS Wt.(%) Oxygen 16.21 Silicon 4.61 Potassium 0.9 Calcium 0.54 Chromium 1.74 Manganese 1.72 Iron 74.29

ELEMENTS Wt.(%) Oxygen 29.41 Calcium 0.49 Chromium 1.05 Manganese 1.63 Iron 67.42

Page 13


10 Scanning Electron Microscopy(SEM) of failed tubing

The sample of the corroded tubing was cut carefully without damaging the internal

corroded surface. The samples were screened at various magnifications under

scanning electron microscope. Scanning electron microscopy of the corroded sample

reveals pitting corrosion which is localized in nature and characterized by formation of

cavities or holes in the material. The figures below show the formation of pits of

varying diameters on the metal surface.

Figure 16 above reveals a localized attack which is wide and flat bottomed .This is

called shadow pitting or mesa type corrosion. In this type of corrosion the protective

iron carbonate layer is worn away in areas rendering the metal vulnerable to

corrosion.

Fig 15: SEM showing 294.12micron pit with streaks

Fig 16: SEM showing mesa attack

Fig 17: SEM showing pits within pit.

Fig 14: SEM showing pits and corrosion product

Page 14


11 Corrosion tests using Autoclave

The gravimetric corrosion rate studies have been carried out in HPHT Autoclave with

coupons fabricated from N-80 and L-80 tubing pieces. The specimen coupon was

exposed to simulated conditions of gas well operating pressure, temperature, flow rate

and partial pressure of corrosive gases. Lowest corrosion rate of 1.09 mpy was

observed with SS-316 grade steel followed by Carbon steel grade-3 with a

corrosion rate of 28.94 mpy. However, severe corrosion rate of the order of 144 mpy

and 93.15 mpy was observed with steel grade N-80 and L-80 respectively. N-80 and L-

80 steel grades are widely used in Oil India Limited as material of construction of oil

field tubulars. The experiment was repeated with different grades of steel for

comparison of corrosion rates. The corrosion rate data generated are tabulated in

Table-11(below).

Table 11: Corrosion rate with different grades of steel

Sample Electrolyte Temp

(˚C)

Pressure

(psi)

RPM

Time

(hrs)

Wt.loss

(gm)

Corrosion inhibitor

Corrosion rate,mpy

N-80 Formation Water(40%)+Condensate(60%)

45 1600 with 30 psi CO2

partial pressure

1400 24 0.3695 No 144

SS-316 Formation Water(40%)+Condensate(60%)

45 1600 with 30 psi CO2

partial pressure

1400 24 0.0025 No 1.09

CS-3 Formation Water(40%)+Condensate(60%)

45 1600 with 30 psi CO2

partial pressure

1400 24 0.0698 No 28.94

N-80 Formation Water(40%)+Condensate(60%)

45 1600 with 30 psi CO2

partial pressure

1400 24 0.1812 Yes 71.53

L-80 Formation Water(40%)+Condensate(60%)

45 1600 with 30 psi CO2

partial pressure

1400 24 0.2789 No 93.15

L-80 Formation Water(40%)+Condensate(60%)

45 1600 with 30 psi CO2

partial pressure

1400 24 0.28 No 101.5

Page 15


The laboratory simulation study in HPHT Autoclave indicates that existing N-80 and L-

80 carbon steel which is widely used for the manufacturing of oil field tubulars are

susceptible to severe corrosion in gas wells containing carbon dioxide. The corrosion

rate was found to be in the higher side (71.53mpy) even after performing the

experiment with three ppm dosing of corrosion inhibitor (Corromin 3014a). Morover,

it is not possible to inject corrosion inhibitor in producing wells with current

completion system. Therefore corrosion inhibition is not the practical solution at

present.

The laboratory simulation study indicates that carbon steel is susceptible to corrosion

and as such is not suitable for use in corrosive environment. Therefore it is appropriate

to select superior grades of steel having better corrosion resistant properties as MOC

(Material of construction) for well tubing in order to maintain the integrity of the well.

12 Results and Discussion

12.1 Water wetting

The majority of production tubing is made of low alloy steel according to specification

of API 5CT. In gas wells, condensation of water occurs when the gas temperature drops

below its water dew point temperature which may be at a particular height in the

tubing depending upon the temperature profile. This condensed water in most cases is

the culprit to cause corrosion by reacting with other corrosive components of the gas.

In tubing containing oil and water mixtures, however upto 90% `free' water may be

contained within an oil emulsion instead of being condensed and will not give rise to

corrosion as long as the flowrate is sufficient to entrain the water. Light gas condensate

does not offer the same protection as oil and in general does not entrain water, so that

water wetting is likely even at very low water cuts. In multiphase (gas-liquid)

conditions the wetting behavior depends strongly on the flow regime and is influenced

by the gas/liquid ratio, production rates, and the angle of inclination of the tubing.[4]

In Lohali#1 the condensate and water flow rate was around 50 bbls/day and 3.150

bbls/day respectively. Water cut in Lohal1#1 was found to be in the range of 0.8% to

6.3% from February -2014 to May-2014 prior to workover. Condensation of water

could be one of the probable reason of tubing corrosion in the deviated section at the

depth of 1094 m as observed in Lohali#1.

Page 16


12.2 CO2 Corrosion

CO2 is one of the main corroding agents in the oil and gas production systems . Dry

CO2 gas is not itself corrosive at the temperatures encountered within oil and gas well

production systems but is so when dissolved in an aqueous phase through which it

can promote an electrochemical reaction between steel and the contacting aqueous

phase . CO2 will mix with the water, forming carbonic acid making the fluid acidic. CO2

corrosion is influenced by temperature, increase in pH value, composition of the

aqueous stream, presence of non-aqueous phases, flow condition, and metal

characteristics and is by far the most prevalent form of attack encountered in oil and

gas production. CO2 corrosion can appear in two principal forms: pitting (localized

attack that results in rapid penetration and removal of metal at a small discrete area)

and mesa attack (a form of CO2 corrosion that occurs in flowing environments, and

occurs where a protective iron carbonate coating is worn away in areas.) At elevated

temperatures, however, iron carbide scale is formed on the oil and gas pipe as a

protective scale.[5]

Visual inspection of the tubing sample revealed structures which resembles pitting,

erosion and mesa attack. The scanning electron microscopy of the failed tubing also

indicated the presence of pits, streaks inside the tube and deterioration of the inside

scale (iron carbonate layer). Worldwide it is observed that 1-3% CO2 content in sweet

gas can cause serious problems in production system. Therefore carbon dioxide

corrosion can be considered as one of the main factor leading to tubing failure of

Lohali#1.

12.3 Erosion Corrosion

Erosion-corrosion deterioration of carbon steel in carbon dioxide (CO2)-saturated

systems with sand is a problem in the oil and gas industry because of the combination

of an aggressive chemical environment and high fluid surface velocities which can

reduce the protection provided by iron-carbonate scale formation or inhibitors by

continuously removing the passive layer. The pressure gradients in the liquid cause

bubbles of vapour to nucleate and almost immediately collapse. This subjects the

inside of a pipe to repetitive localized stress and the material erodes away causing

increased corrosion rate and forming cavitation. The erosion corrosion is further

aggravated where the high turbulence flow regime is accompanied by presence of

abrasive suspended material like sand .

Page 17


In Lohali#1 high velocity of gas through 2.7/8” tubing accompanied by sand ingression

might have resulted in erosion corrosion which is apparent from the streaks present in

the inside surface. The condensate particles also might have created hammering effect

on the wall of the tubing thereby aggravating the corrosion problem. In Lohali#1, the

failure zone occurred at the deviated section of the well (1094m) where the chances of

liquid impingement (condensate and water) along with abrasive sands is maximum.

The streaks, typical of erosion corrosion as shown in Fig 18 is also visible in the inside

surface of the tubing recovered from the failure zone as seen in Fig 19. Therefore

corrosion due to erosion at high fluid velocity and the effect of abrasive sand can be a

major contributing factor leading to tubing failure of Lohali#1.

Fig 18: Typical signs of erosion corrosion

Fig 19: Eroded tubing of Lohali#1 showing streaks

13 Analysis of wells completed in NHK285 block.

A total number of nine wells have been completed in Deohal Barail 3rd Sand

reservoir(Well NHK285 Block) including Lohali#1. Out of the nine wells of NHK-285

block, six producing wells e.g NHK537E has been completed with 2.7/8” L-80 tubing,

NHK552D with 3.1/2” tubing , NHK602 with 2.7/8” N-80 tubing with gravel pack,

NHK609 with 4.1/2” N-80 tubing with gravel pack, NHK-613 with 4.1/2” N-80 tubing

with gravel pack and LHL001D with 3.1/2” N-80 tubing with gravel pack.

The three nonproducing wells in the same reservoir are NHK285 with 2.7/8”

completion tubing, NHK558 with 2.7/8” completion tubing and NHK611 with 2.7/8”

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tubing with screen in horizontal section. Similar corrosion phenomena has been

observed in few other wells in the same reservoir, NHK285 had to be abandoned

,NHK558 is also planned to be abandoned and NHK611 was recently killed due to

sudden gas leakage through wellhead.

All these failures are anticipated to be due to corrosion problem. The oil field tubulars

of all the wells in Deohal area are exposed to corrosive gas like carbon dioxide coupled

with sand ingression problem and high gas flow rate, the chances of corrosion taking

place in all the wells is likely to be extremely high. The corrosion of same intensity is

also expected for other wells planned to be completed in Deohal Barail 3rd Sand

reservoir in the coming future.

14 Conclusions

1. Corrosion rates calculated using N-80 and L-80 coupons were found to be higher as

compared to carbon steel grade3.

2. Carbon dioxide partial pressures of 1.84% and 2.26% in the flowing gas have

significantly contributed to the high corrosion rate observed.

3. Presence of small water cuts in the range of 0.8-6.3% have contributed to wetting of

the inside of tubing surface due to non entrainment of water in gas condensate wells.

This phenomena is also responsible for the corrosion observed in Lohali#1.

4. Erosion corrosion arising out of high gas velocities through 2.7/8” tubing coupled

with abrasive action of sand played a major role which lead to tubing failure of

Lohali#1.

5. The formation of carbonic acid in presence of water vapour and high carbon dioxide

in the gas made the environment highly conducive to corrosion.

6. All the wells are having high production potential and reservoir is prone to sand

production thereby increasing the possibility of accelerating erosion corrosion.

15 Recommendations

1. Selection of alloys having excellent strength and better resistance to corrosion

needs to be done in order to ensure that tubing failures such as Lohali#1 can be

minimized in the future.

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2. Emphasis should be given on redesign of the system to reduce the flow velocity,

turbulence, cavitation or impingement of the environment. This can be achieved by

using higher size diameter tubing which would reduce the flow rate of the flowing

fluid.

3. Wells should not be kept uninhibited during the shut in periods as carbon steel is

susceptible to general corrosion without any inhibition.

4. Analysis of gas and liquid samples from the well head needs to be performed in the

laboratory on a periodic basis to get an idea of the CO2 content of flowing gas and

corrosion rate of the fluid so that precautionary measures can be taken beforehand to

deal with the corrosion problem.

5. For critical wells which are prone to corrosion , Multi Finger Imaging Tool(MIT) is a

useful tool which should be run on a periodic basis to get an idea about the thickness of

the tubing. The thickness value so obtained can be correlated with the previous

readings to ascertain the magnitude of degradation. This technique would be

extremely useful to know the condition of oil field tubulars at any point of time and for

taking preventive actions.

6. Protective coatings including plastic linings can be incorporated at the

manufacturing stage to increase the life period of oilfield tubulars prone to corrosion.

16 Acknowledgement

The authors thank Shri B.C. Dutta, GM(Chemical), OIL, Duliajan for his encouragement

and guidance during the course of preparation of the note. The contributions and

valuable suggestions of Shri S.K. Mishra, GM(Chemical)I/C and Mr. M.C. Nihalani ,

Head(R&D-Projects) in course of accomplishment of the study have been thankfully

acknowledged.

Debajani Bose Head-Chemical (P&A)

Subodh Purohit Surajit Das

Dy.SRS (R&D) Dy.S.C. (Chemical)

Dilowar Hussain Laskar Jitendra Kumar Dy. SE (prod-gas) Sr.Reservoir Engineer

Page 20


17 Bibliography

[1] Gupta M, Boinapally K, Cao Y Lusk D, "Armoured against corrosion,"

Hydrocarbon Engineering, vol. 13, no. 1, pp. 115-118, 2008.

[2] Roberge PR, Handbook of Corrosion Engineering. New York: McGraw-Hill,

2000.

[3] Marcus P, Corrosion mechanisms in theory and practice, Second Edition ed.

New York: Marcel Dekker, Inc., 2002.

[4] L. Smith, British Corrosion Journal 1999 Vol. 34 No. 4 247

[5] Popoola et al. International Journal of Industrial Chemistry 2013, 4:35

Page 21


Annexure-I(Detailed Well History)

The well LHL001 was drilled in February 2002 to probe the hydrocarbon prospects

down to basement in Lohali structure. On testing the 3821 m Lk+Th sand through

perforations in the range 3820.5 – 3822.5 m, the well gave inflow of formation water

only without any trace of oil or gas. The sand was plugged back by setting bridge plug

at 3815 m.

On testing 3799 m Lk+Th sand through perforations in the range 3799 – 3801 m, no

immediate pressure build up was observed. Upon unloading, pressure gradually rose

to 31.6 ksc both in tubing and casing. The well displaced floating oil (API – 25.6°) with

water. On further unloading, the well produced formation water only. In view of poor

inflow of oil along with formation water, Lk+Th Sand was tested higher up at 3772 m

through perforations in the range 3771 – 3773 m after plugging back the existing sand

at 3799 m. No immediate pressure build up was observed. The bottom hole sample

collected using sand bailer showed heavy/high pour point oil (API – 11.8°, softening

point – 72°C). The bottom up sample collected showed oil – Nil & water – 100%

(salinity – 2500 ppm).

The sand at 3772 m was plugged back due to no inflow of oil and the 3754 m Lk+Th

sand was tested through perforations in the range 3753 – 3755 m. No immediate

pressure build up was observed. However on opening, the well displaced sluggishly.

The well was kept shut in for overnight and the following morning it was found that

the casing and tubing pressure had increased to 35 ksc. Floating oil sample analysis

showed oil – 57% (API- 26°, pour point – 33°C). Upon further unloading (cum: 54.4

kls), sample analysis showed oil – 99% (API – 25.3°). The master sample analysis

showed 4% oil with 96% water (salinity – 5400 ppm, HCO3 – 305 ppm). The well was

produced through well head set up @ 20-42 klpd through 6 mm bean with negligible

FTHP. Sample analysis showed oil- 3-4%, water – 94-97 % (salinity – 5400 ppm, HCO3–

366 ppm). The SBHP recorded in April 2002 was found to be 408.26 ksc (35 ksc above

hydrostatic). The well was kept shut in since April 2002.

In a workover carried out during May-July 2009, 3754 m Lk+Th sand was tested

through live condition perforation in the range 3753-3756 m. A total of around 369

bbls of well fluid was unloaded. The sample analysis showed water – 100% (pH – 7.5,

salinity – 5400 ppm, CO3 – 0 ppm, HCO3 – 305 ppm).It was then decided to test 2438 m

Barail Sand after recovering 5.1/2” casing. Accordingly, bridge plug was set at 3105

and 5.1/2” casing was punctured in the range 3094.4 – 3095.55 m. Circulation was

established and the well fluid was changed over to 70 pcf Na-formate solution. 5.1/2”

casing was then cut at 3086.5m, 3081.5, 2970 m and at 2949.8 using jet cutter and split

Page 22


shot cutter. However, the 5.1/2” casing could not be recovered. Thereafter a cement

plug covering the range 2966 – 2853 m was placed in two attempts and the 2.7/8”

production string with bull plug & perforated tube was lowered to 98.11 m. The well

was kept shut-in since then.

In a subsequent workover operation carried out during August-September 2010, the

well was killed with 70 pcf sodium formate solution and the 5.1/2” casing was cut at

2840 m and recovered. Bridge plug was set at 2837 m and 1 m of cement was dumped

over the set bridge plug. After changing over to water, casing integrity test for the

9.5/8” casing was carried out by pressurizing the casing upto 2500 psi with water. The

well fluid was again changed over from water to 77 pcf sodium formate solution.

Thereafter, a dummy trip down to 2828 m was made and it recorded CBL-VDL-GR-CCL

log in the range 2817 m to 1200 m which showed good cement bonding. Subsequently,

the well was perforated in the range 2461 – 2464 m and 2458 – 2461 m using 4” HSC

gun. After unloading 47 bbls of well fluid, the well was diverted to OCS and put on

production @ 1,15,000 SCMD gas with 25 klpd condensate through 7 mm bean with

FTHP of 185 ksc and CHP of 126 ksc. The well had been on continuous production

since September 2010.

On 28.01.2012, the hole probed using 1.5/8” sand bailer which got settled at 2765 m

and found sand in the return sample. In order to augment gas production, live

condition extension of perforation was carried out in the well in the same 2438-m

Barail Sand through perforations in the range 2449-2455 m using 2.1/8" Deep Star

Millennium gun on 10.02.2012. However, there was no significant improvement of gas

production behaviour was observed after carrying out LCP. The well was on

continuous production since then. In June-2014, it was decided to recomplete the well

(2438-Barail sand) with gravel pack & 3.1/2" OD completion string in order to mitigate

the sand ingression problem.

On 01/07/2014, after pumping around 338 bbl of 2% KCl solution as kill fluid through

casing, no fluid return was observed through tubing and the subsequent THP and CHP

were observed to be nil. After this, X-Mass tree was rigged down and BOP was rigged

up to facilitate unsetting of Production Packer. The packer was unset with vertical pull

of 82,000 Ibs. But after pulling approximately 6 m of tubing out of the hole, the string

weight suddenly dropped to 17,000 Ibs indicating a rupture of tubing. It was eventually

observed that tubing got parted off at 1094 m depth and the remaining part of tubing

fell into well sump as fish. Thereafter, fish recovery job was done on 04/07/2014

wherein the parted portion of tubing that remained inside hole was recovered at

surface. After recovering the tubing, it was found that tubings were severely corroded

and were having several holes.

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