hybrid : CRA-C steel well completion

1. Corrosion Resistant Alloy (CRA)-
Carbon Steel Combination (Hybrid)
Material of Construction (MOC)
strategy of
Well Completion
For Severe Corrosive
Oil & Gas Field Development
Presented By: Subrahmanya Bhat
Materials & Corrosion Section
Institute of Engineering & Ocean Technology
Oil and Natural Gas Corporation Limited
1

2. Outline of Presentation
 Background
 Description of Problem
 Approach of Analysis
 Identification of technologies and solution:
 Evolution of the options:
 Summary and Recommendations
2

3. Background
Severe Down Hole Corrosion In ONGC Fields
 B-193 marginal field – B&S Asset –Western offshore :
H2S : 40000 ppm - HSE issue: Wrong MOC – failure -
few hours - through cracking, 1000ppm H2S leak : fatal
 In –situ- Combustion – EOR : Santhal & Balol
Pilot air injection – EOR for Gamij, Ahmedabad
Injector wells : High Temp – Oxidation
450 -500°C : Santhal & Balol (heavy oil)
350°C : Gamij, Ahmedabad (light oil)
HSE issue: Casing failure – internal blow out/bypass to
near surface tube well water reservoir-pollution
complication
3

4. Profitability of hydrocarbon exploitation
 CAPEX - conduits, containment vessels
and process equipments.
 OPEX - process costs
 Cost of conduits, containment vessels, and
process equipments depends on MOC.
 Optimize MOC with process control -
reduce total cost of production.
 Facilitate sustained profitability without
Sacrificing HSE issues.
4

5. MOC - current study
 Well completion: Casing, tubing, packer for high
sour oil & gas wells
 Well completion : Casing, tubing, packer for
injector wells of in-situ combustion scheme of
EOR
5

6. Sour oil & gas : Marginal field development
(Bassein & Satellite Asset)
 B-193 cluster: B-193, B-178 , B-172,
B-179,B-28-A,B-23-A, B-28 & B-180 fields:
H2S(40000 ppm) CO2 (4 -11%)
In-place oil : 20.86 MMt
 B-22 cluster - B-22, BS-12, BS-13, B-149-1,
B-149-3 fields : CO2 gas (5%) H2S (230ppm)
In place oil : 10 MMT & gas : 10.02 BCM
 Location- Heera-Panna-Bassein block
60-90km - from Mumbai city
 water depth : 70m
6

7. B-193 : Bassein Formation : Corrosion Severity
Parameters Oil Wells Gas Well (B-28-2)
p-CO2, psi 87 -190 172
p -H2S, psi 27 - 111 86
Ratio of p -CO2/ p -H2S 2 – 3.2 2
pH 3.3 – 3.6 3.3
BHT, °C 91 - 136 133
Cor.rate, mm/y 4.5 – 20.6 33.4
7

8. B-193 : Mukta Formation: Corrosion Severity
Parameters Oil Wells Gas Wells
p-CO2, psi 28 - 80 40 – 88
p -H2S, psi 0.4 - 46 2.6 - 29
Ratio of p -CO2/ p -H2S 1.3 -80 2.2 - 104
pH 3.6 – 3.9 3.6 – 3.7
BHT, °C 101 - 120 133
Cor.rate, mm/y 2–6 4.44 - 19.2
8

9. B-193 : Panna Formation: Corrosion Severity
Parameters Oil Wells Gas Wells
p-CO2, psi 354-367 165 - 551
p -H2S, psi 0.15 0.01 - 0.16
Ratio of p -CO2/ p -H2S 2368 1112 - 11120
pH 3.2 – 3.3 3.2 – 3.3
BHT, °C 145 -162 122 - 158
Cor.rate, mm/y 7.71 -20.7 11.7 - 104.0
9

10. B-22: Corrosion Severity
Parameters Oil Well Gas Wells
(B-22-5)
p-CO2, psi 99 32 - 129
p -H2S, psi 0.46 0.01 – 0.523
Ratio of p -CO2/ p -H2S 215 247 - 3100
pH 3.6 3.6 – 3.9
BHT, °C 90 90-100
Cor.rate, mm/y 1.55 2.32 – 31.6
10

11. Severe Sour Fields of World
Field Temp p-CO2 p-H2S Salinity Wells
°C psi psi g/l Alloy
Hunield field 140 225 470 <2 N06987,N06625
Oklahoma, USA N1027
Big Escambia Creek 140 750 140 <2 N06985,N06625
field, Oklahoma, USA N08028,N08825
Offshore south 200 600 450 17 UNS N08028
Texas
Labarge Field, 140 220 2600 200 N06975
Wyoming, USA
Big Horn filed, 220 1050 1800 200 N10276
Wyoming, USA
B-193, India 139 190 111 18.7 Proposed by IEOT
N08028
11

12. Guidelines
 UK Offshore Industry HSE document, UK
 NACE, USA
 API, USA
 NORSOK, Norway
 Alberta Energy Utility Board, Canada
 JNOC Research Center, Japan
 Nickel Development Institute, Canada
12

13. Standards/Documents for - Sour Service
 NACE MR0175/ISO15156 (2003)
 CAPP -Recommended practice for Sour gas,
2003
 European Federation Of Corrosion Publication
No 16, Carbon steel, 2002
 European Federation Of Corrosion Publication
No. 17, CRA, 2002
 Alberta Energy Utility Board Directive,
2008
 Materials Selection For Petroleum Refineries
And Gathering Facilities, NACE International
13

14. Approach of analysis
 Assess severity - design parameters
 Carbon or low alloy steel suitability
 Carbon or low alloy steel nonsuitability
 Corrosion Resistant Alloy suitability
 Identify CRA
 CRA as per standards
 Documentation - Performance of CRA
 Cor.rate limit - CRA : 0.05mm/y (2mpy) and resistance
to cracking.
 Take into account Consequence of failure
(safety, business loss & environmental damage
1000ppm H2S leak : fatal)
 Minimize HSE risks & Use Field proven MOC
14

15. Selection Criteria
 Mandatory requirements
Comply with NACE MR0175, API
 Design Conditions
For new technology ensure greater safety
 Operating conditions
Mature technologies with history of successful
applications
 Design temperature
 Process requirements
 Special requirements - e.g. Design life
15

16. Corrosion severity grading
 Flow dynamics (gas vel <4-6m/s : water hold at
bottom, Liquid vel <0.4m/s, higher risk of water
wetting)
 Temperature & Pressure
 Moisture content
 pH
 Chloride, Sulphate & Volatile fatty acids
 Calcium / Bicarbonate Ratio
 CO2 mole %, H2S PPM
 Solid Sulphur %
 partial pressure of CO2 and H2S and their ratio.
16

17. Temperature effects
T, °C Alloy, environment Corrosion
<60 C steel, p-H2S < 0.05psi No SSC
<60 NACE C steel, any p- H2S pressure No SSC
<60 13 Cr , p-H2S < 1.5psi No SSC
<60 18Cr-3Ni (S304, S316), p-H2S <14psi, No SCC
<60 Duplex, if p-H2S < 10psi No SSC
<60 Ni-Cr-Mo Alloy, any p-H2S pressure No SSC
>60 C steel, p-H2S < 0.05psi No SSC
>60 NACE C steel, any p- H2S pressure No SSC
>60 13 Cr , p-H2S < 1.5psi, T < 150 °C No SSC
>60 18Cr-3Ni (S304, S316), p-H2S <14psi, No SSC
Chloride < 50ppm
>60 Duplex, if p-H2S < 10psi No SSC
>60 Ni-Cr-Mo Alloy, any p-H2S pressure No SSC
(Increase Mo to increase resistance to 17
pitting/crevice corrosion)

18. CO2 dominant mechanism
Partial pressure - Carbon dioxide (p-CO2)
 < 7 psi : noncorrosive
 Exception to above – If VFA >300ppm
 7 to 15 psi : may be corrosive
 15 to 30 psi : corrosive
 > 30 psi : very severe corrosive
 Stable FeCO3 - temperature : 60 - 120°C
 Ca++/HCO3- < 0.05 – 0.1 : Corrosion risk low
 Ca++/HCO3- > 0.1 : Corrosion risk high
 If p-CO2/p-H2S >500, & p-H2S <0.01psi
18

19. CO2 + H2S environment
 p-H2S is < 0.01 psi
CO2 dominant mechanism
 p-H2S is ≥ 0.05 psi : NACE sour medium
MOC must comply NACE MR0175/ ISO15156
 Ratio p- CO2 / p-H2S
< 20 : Severe sour Mechanism
20-500 : Transition
>500 : CO2 mechanism
 p-H2S > 10psi likelihood - solid Sulphur
(If drastic pressure loss at well bore)
 S deposition certain – if H2S >5% : in just 3-4 hours
bottom hole may get choked up with S
S problem significantly low in Oil wells
19

20. Beneficial effect of Mackinawite
 0.05 to 1.25psi : p- H2S
10 to 50% of predicted for CO2 alone
environment
Mackinawite :FexSy with Fe : 50.9 to 51.6%
If pH is >5 Excellent protective sulphide
 If pH : 4.0 to 5.0 transition effects
 If pH 3.5 – 4.0 localized deformation of
sulphide
20

21. CO2 + H2S
Poor Protective sulphide scale: high
corrosion
 If High CO2 + High H2S
Protective Sulphide scale: low corrosion
 Low CO2 + High H2S
 Low CO2 + Low H2S
 High H2S
Pitting & Crevice at high H2S likely
21

22. Guideline on p-CO2 X pH
 If p- CO2 > 87psi
pH < 3.5
 If p-CO2 : 87 – 8.7psi
pH : 3.5 to 4.0 (depends on p-H2S)
 If p-CO2 < 8.7psi
pH >4.0
22

23. Flow dynamics and Bubble point
 Deviated well Corr. failure - lower half side tubing
 Oil wells Log -water content of flowing emulsion :
Increase in water with depth
 Bubble point – near wellhead: release of acid gases
from oil phase into gas phase near wellhead
Less likely availability of acid gas at well bottom
Take calculated risk - carbon steel casing
23

24. Industry Practices: Reported in public domain
 UK Offshore HSE document (Practiced in US,
Canada also)
 Greater than 6mm/year : CRA
 Less than 6mm/year : carbon steel
(corrosion allowance, inhibition and process
control)
 NACE Paper on practices at British Petroleum
fields
 Cut off value : 8mm/year
 NORSOK M-001 standard
 Cut off value for inhibited cor. rate :
10mm/design life years
24

25. Specific precautions for sour wells
Sulphur deposition problems
Normally oil wells – do not take place
In HPHT gas wells – likely deposition if T <110°C & H2S
mole % > 5
 If PVT study shows S deposition at well P & T
 If de-aeration of well completion fluids not done-
oxygen influx into formation
Oxygen with H2S forms S
Solid S – severe deposition in downhole
S is very corrosive
Must – periodic Sulphur solvent treatment
25

26. Carbon steel Acceptance
 p-CO2 <3psi, p-H2S <0.05psi T: 60-120°C
Use Cor.Allowance(CA)
 p-CO2 >3psi, p-H2S<0.05psi, T:60-120°C
Cor.rate < 6mm/y
Use Inhibitor + CA,
 p-CO2>3psi, p-H2S>0.05psi, T>60°C, Chloride<5000
Cor.rate <6 mm/y
NACE C steel +Inhibitor + CA
 p-H2S >0.05psi, p-CO2/p-H2S >500
Cor.rate < 6mm/y
NACE Carbon Steel + Inhibition + CA 26

27. CRA selection
Sweet service, T<100C 9 Cr-1Mo
Sweet service, T<150C 13 Cr
Sour, p-H2S<1.5psi, Cl<10000ppm T<150C 13Cr
Sour, p-H2S<3psi, Cl < 100000ppm Cold worked Duplex/Super
duplex
Sour p-H2S<10psi, Cl <100000ppm Annealed Duplex
Sour, p-H2S : any value, No Sulphur Ni-Cr-Mo (Ni >22%)
Alloy 28, Incoloy 825
Sour p-H2S <70psi, S, chloride : any, T < 204°C Incoloy 625
Sour p-H2S >70psi, S, chloride : any T < 232°C C-276
27

28. B-193 cluster wells study
 Superficial liquid velocity << 0.4m/s
Water wetting of bottom hole tubular
 p-H2S > 1.25psi,
No protective scaling by Mackinawite
 High electrochemical metal dissolution
Cor.rate > 6mm/y & pH 3.3 - 3.5
 Severity higher for gas wells than oil wells.
 High CO2 & High H2S
 NACE Carbon steel take care of Cracking failures
 NACE Carbon steel can not contain high metal dissolution
 Difficult to get corrosion inhibitor with >95% inhibition
 Carbon steel ruled out
 Solution : CRA MOC
28

29. B-193 wells MOC
 Alloys Nickel (Min 22%) resistant to chloride stress corrosion
cracking (CSCC)
 Nickel resist stress corrosion cracking (SCC) in the presence of
chlorides. Higher Chloride : Ni 22% (min)
 Nickel + Molybdenum resists sulphide stress corrosion cracking
(SSCC).
 Chromium + Molybdenum resists pitting/crevice
 Higher H2S, pitting/crevice increase: increase Mo.
For B-193 design conditions : (T<149ºC, Cl <25000ppm)
 Chromium 19.5 to 20% , Nickel 25% to 29.5% and
Molybdenum 2.5 to 4%
 Alloy 28 (UNS N08028)
29

30. B-22 Wells MOC
 High CO2 + Low H2S category
 Partial pressure of H2S < 1.5 psi
 T : 100°C
 pH - 3.6 to 3.9
 P-CO2 > 32 - 130 psi
 Corrosion rate : 1.55 -31.6mm/y
 High Chrome steel (>11% Cr ) resistant
 13 Chromium steel : API 5CT L80 Type 13 Cr
30

31. Tubular MOC for B-193 & B-22
 C steel not adequate ( with CA & inhibition)
 Conclusion : CRA – Alloy 28 or 13 Cr steel
 Solid wall tubular CRA - high CAPEX
Relative Cost comparison
C steel : 1.00
NACE C steel : 1.04
13 Cr steel : 4.00
Alloy 28 : 10.00
31

32. Reports of Cost effective -CRA Well completions
 2001: Cheveron Canada – Fort Liard gas wells
( Tail pipe, tubing below packer : High Nickel
alloy
 2004: ExxonMobil – Big Escambia Creek field,
USA:Sour gas – Incoloy 825 as tail tubing below
mandrel for cor.inhibitor
 2004: Shell Global & Abu Dhabi National Oil Co.
(ADNOC) - Bottom CRA (below CRA packer) for
33%H2S gas wells
 2004: IEOT Recommended - CRA liner for
bottom 200m of ISC injector wells – Santhal &
Balol fields, Mehsana
 2002: Acid gas disposal wells at Canada – CRA
for injection zone
32

33. Proposal for Well completion
Hybrid type : CRA – Carbon steel combination
And
Adoption of Technology for
 Tubing integrity
Internal tubing- CRA clad
Technology developed in US
 Galvanic Corrosion Prevention
Couple as per USA patent 5906400
Coating as per guideline of NORSOK M-001
33

34. B-193(Bassein & Mukta)
Summary of Well Completion Metallurgy
Casing : Well Bottom up to 10 m (or Alloy 28
one single casing) above the Packer
Casing : Rest to Well head API 5CT L-80
Packer Incoloy 825
Tubing : Well Bottom up to 10 m (or Alloy 28
one single tubing) above the Packer
Tubing : Rest to Well head Alloy 28 clad on API 5CT
L-80
34

35. Well Completion : B-193 Wells
35

36. B-193 (Panna Formation) & B-22
Summary of Well Completion Metallurgy
Casing : Well Bottom up to 10 API 5 CT L-80 Type
m (or one single casing) above 13 Cr Steel
the Packer
Casing : Rest to Well head API 5CT L-80
Packer 13 Cr Steel
Tubing API 5 CT L-80 Type
13 Cr Steel
36

37. Well Completion : B-22 Wells
37

38. Bimetallic Galvanic Corrosion
38

39. Galvanic Corrosion
 Evolution of H at cathode surface is possible if electron
from anodic reaction flow through cathode surface and
reacts with H+ from acid gases
 Effective distance of electron flow on cathodic alloy from
interface : 5 times the diameter of tubing/casing
 If above reaction favored – increase anodic forward
reaction & Severe electrochemical dissolution of anode
corrosion (localized only on anode)
 If severe H release at cathode, SSC susceptible CRA
cracks
 Anode : carbon steel; Cathode : CRA
 Basis for prevention : blocking cathodic reaction in first
10 X dia of tubing/casing
39

40. Galvanic corrosion prevention
Couple features
1. Design as per USA Patent, 5906400, 5.5.1999
2. Coating as per NORSOK M-001 standard,
August, 2004 Guideline:
High temperature resistant coating length
The length “d” : 10 times the diameter of the casing
pipe :
for 7 inch casing, d = 6 feet
40

41. High Temperature Oxidation Environment
 Injector wells of In-situ combustion(ISC) for
EOR, at Santhal and Balol heavy oil fields of
Mehsana Asset
 Injector wells of Air Injection Pilot for EOR at
Gamij light oil field, Ahmedabad Asset.
41

42. In-Situ-Combustion EOR process
42

43. Well Bottom : High temperature Oxidation
Combustion front temperature:
Initial temperature
 450 – 550 ˚C for ISC injector wells : Heavy oil
 350 ˚C Injector wells : light oil
Stable temperature : 70 ˚C
(During air/water injection)
 Air injection under high pressure
 Alternate Water Injection under high pressure
43

44. MOC for In –Situ-Combustion Injector Wells
 9 % Cr steel resistant to High temperature
oxidation, alternate moist air and
injection water
 Upset : influx of flue gases –CO2 & heat
from the burning front
 Conservative Approach : 13 Chromium
steel (UNS S42000)
 Well Completion similar to B-22 well.
44

45. Well Completion : ISC injector wells
Final casing, 7 inch ф
Final casing 7 inch
3 ½ inch ф Tubing, 13 Cr steel
Tubing, 13 Cr
45

46. In-Situ-Combustion Injector Wells
Summary of Well Completion Metallurgy
Casing : Well Bottom up to API 5 CT L-80 Type 13
10 m (or one single casing) Cr Steel
above the Packer
Casing : Rest to Well head API 5CT L-80 Type 1
Packer 13 Cr Steel
Tubing API 5 CT L-80 Type 13
Cr Steel
46

47. Summary and Recommendations
Novel hybrid well completion metallurgy –technically feasible
for : Sour oil & gas wells and ISC injector wells.
Casing:
 Casing - CRA component in the bottom hole up to one
single above CRA packer (Incoloy 825)
 Casing- Rest to well head - carbon steel.
1. with galvanic corrosion prevention couple
2. With NORSOK M001 Aug 2004 guideline for Coating
Tubing:
1. With Tubing integrity by Internal CRA clad for Sour wells.
2. Solid CRA tubing for ISC injector wells.
 CRA for high H2S wells of B-193 : Alloy28
 CRA for High CO2 wells of B-22 : 13 Cr
 CRA for ISC Injector wells : 13 Cr
47

48. Thanks
48