Weight Loss Sour Corrosion | Materials And Corrosion Control

Damage Description

Critical factors

·         For H₂S/CO₂<0.3 and H₂S>100 ppm : for tubing (Alloy-28 or higher), for machining parts (nickel-base PH CRAs such as
I-718, I-925, higher

·         Material selection is strongly tied up with a work-over strategy.

·         H₂S content, pH, temperature, velocity and oxygen concentration are all critical factors.

·         H₂S/CO₂ ratio: Sour wells generally co-produce sweet gas as well. So, a H₂S/CO₂ ratio is one of the critical factors controlling sour weight loss corrosion.

·         Sour corrosion is flow-dependent. Flow regime and flow rate with temperature are one of the dominant factors controlling sweet corrosion. The passivity of the corrosion products is affected by flow velocity, flow character, H₂S/CO₂ ratio, water cut, hydrocarbon type.

·         Unlike sweet corrosion, sour corrosion is almost independent to temperature

·         However, sour corrosion becomes very aggressive in the presence of strong oxidizers such as dissolved oxygen. Iron sulfide itself could promote galvanic effect when iron sulfide partially covers a steel surface but its tendency promoting localized corrosion is not as aggressive as other strong oxidizers.

Affected Units or Equipment

§  Production: Wellhead components, tubing hangers, hanger subs, R & X nipples, flow couplings, production tubing, casing, production liner, tail pipe, PBR seal and packer assemblies, sand screens, and other downhole accessories

§  Drilling: drill pipe, heavy weight drill pipe, drill collars, drill jars, cross-over subs, tool joints, drill bits, bit subs, Kellys,

§  Workover: coiled tubing, wirelines, fishing tools (over-shots, tubing/casing spears, milling tools, reverse circulating junk catchers, fishing magnets, fishing jars, wash over pipe)

Appearance or Morphology of Damage

·         Localized corrosion would occur in sour gas wells where gas flow rates affect flow regime inside the tubing but the metal loss is not as aggressive as classical pitting corrosion. It can be called as localized weight loss corrosion.

·         Localized corrosion or localized under-deposit attack can occur, especially if oxygen or elemental sulfur is present.

Prevention/Mitigation

Limited application of corrosion inhibitors for downhole treatment because of the lack of treatment facilities.

Material selection or corrosion inhibitor treatment is oftentimes employed for mitigation.

A continuous corrosion inhibitor treatment is oftentimes employed for protecting surface facilities such as flowlines and trunklines in sour service. But proper materials selection is cost-effective for sub-surface facilities.

When a H₂S/CO₂ ratio is less than 0.2 (?), Alloy-28 needs to be employed for downhole equipment.  Carbon steel can be used when H₂S/CO₂ ratio is greater than 0.2 but a workover strategy should be consulted.

  Inspection/Monitoring

·         Evidence of locally thinned areas for surface facilities can be found using scanning ultrasonic thickness methods or profile radiography.

·         For carbon steel, damage is usually in the form general thinning but may be highly localized to specific areas of high velocity or turbulence, typically where a water phase is condensing.

·         Process and corrosion monitoring are important aspects of a well-developed program to minimize the effects of acidic sour water corrosion.

·         Properly placed corrosion probes and corrosion coupons provide additional information on the rate and extent of potential damage for surface facilities.

Inspection Frequency

KPIs

·         Surface: corrosion <5 mpy

Competencies and Training

§  e-COE 101 Corrosion Basics

§  e-COE 701 Corrosion & Corrosion Prevention

§  PEW 407 Corrosion Technology

§  COE 104 Chemical Treatment for Producing Operations

Reference Resources (Standards/GIs/BPs)

·         ISO 15156 (NACE MR0175-2002)

·         NACE “H₂S Corrosion in Oil and Gas Production – A compilation of Classic Papers (1981)

·         API “Corrosion of Oil and Gas-Well Equipment,1990

·         NACE “Corrosion Control in Petroleum Production” TPC Publication 5, 1999

·         Bruce D. Craig, “The Nature of Sulfides Formed on Steel in an H₂S-O₂ Environment,” CORROSION Vol. 35, No. 3,
March 1979, p. 136-138.

·         C. P. Dillon, “Corrosion Control in the Chemical Process Industries,” MTI Publication No. 45, Second Edition,
NACE International, Houston, TX, 1994.

·         Denny A. Jones, “Principles and Prevention of Corrosion,” Prentice-Hall, Inc., NY, 1996.

·         Bruce D. Craig, “Sour-Gas Design Considerations,” Society of Petroleum Engineers (SPE) Monograph Series, Monograph Volume 15, TX, 1993.