S Bhat Prod Con2009

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hybrid : CRA-C steel well completion

hybrid : CRA-C steel well completion

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  • 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