A Part of "Corrosion: Technical and Economic Driver for Indonesia Oil and Gas Industry" Petroenergy Magazine Edition Jan -Feb 2008
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Corrosion engineering was long time developed in 18th century by Sir Humphrey Davy for copper wooden ships. This engineering discipline then emerged along with development of corrosion resistance material technology, coating, and inspection technologies. Corrosion is a natural tendency of materials to return to their most thermodynamically stable state. This process is usually deteriorative to materials. Corrosion control to prevent this deterioration is by three general ways: control the environment, design the materials, and design a barrier between the material and its environment. A typical approach for corrosion control program applicable for oil and gas industry can be seen in Figure 1.
Figure 1 - Typical Corrosion Control
Knowledge basis for corrosion phenomenon is a thermochemical process. There are eight basic form of corrosion common in petroleum production and process industry, Table 1. Other special form of corrosion that associated with specific hydrocarbon and refining industries are: carburation and metal dusting. Understanding corrosion mechanisms will be much helpful to develop corrosion control practice.
Table 1 -Summarized Corrosion Mode
Corrosion can attack almost all engineering structures equipments and systems: fixed/floating offshore structure, piping system, storage tank, vessel, boiler, etc. Detrimental effects can occur when corrosion accompanied synergistically by mechanical load (static, cyclic). More concern should be given due to stress corrosion cracking, pitting, and intergranular corrosion as these types of corrosion is the most cause of failure in gas pipeline and process industry.
Corrosion Resistance Materials Selection
Beside general requirement in mechanical basis, fabrication, maintainability, and cost, design of materials for corrosion protection should evaluate corrosivity variables as follow but not limited to:
- CO2 content;
- H2S content;
- Oxygen or oxidizing agents content;
- Operating temperature and pressure
- Erosion; and
- Organic Acid and Halide
For many provided guidelines, reference, and recommended practice in oil and gas industry, care should be taken for specific condition of operation variables, environment, and type of equipment and the possibility to introduce specific corrosion mechanism. Output of material selection program is appropriate materials for specific service condition as well as assurance for fabrication and maintainability. Several selection guideline and verification tools considerable for material procurement are as follow:
- Guideline for materials selection for corrosion protection:
> API 5L (general material requirement for oil and gas production)
> NACE MR 0175 (carbon and low alloy selection)
> EFC Document Number 16 (carbon and low alloy for H2S service)
> EFC Document Number 23 (carbon and low alloy for CO2 service)
> Norsok M-001 (corrosion materials for offshore and onshore)
> ISO 15156 Series (corrosion materials for H2S service)
> DNV RP F-112 Draft Version April 2006(duplex stainless steel design for subsea application)
> DNV OS B-101 (corrosion resistant metal for offshore application)
- Corrosion testing of material:
> NACE TM-0177 or EFC Document Number 17 (SCC laboratory test)
> NACE TM-0284 (HIC laboratory test method)
> ASTM G-150:99R04 and ASTM G-0048:03 (critical pitting temperature test method)
> AWS A4.2-91 or ISO 8249 (ferrite number of duplex stainless steel conversion from magnetic measurement)
Protective Coating
Coating is primary corrosion protection method for metals. Corrosion protective performance of coating can be evaluated from the following:
- Mechanical resistance and adhesion;
- Chemical stability;
- Permeability for corrosive agents;
- Electrochemical stability;
Coating for corrosion protection can be broadly divided into: metallic (zinc, chromium, aluminum), inorganic (enamels, glasses, ceramic, glass reinforced lining), and organic coatings (epoxies, alkyd, acrylics, polyurethanes). Steel Structures Painting Council (SSPC) as authorized organization in coating technology provides a series in coating guidelines consist of:
- Surface Preparation Standard;
- Painting System and Coating System Standards Guide and Specification;
- Qualification Procedures and Quality System
Corrosion Inhibitor
Inhibition is alternative corrosion control in oil and gas production, complementary to corrosion resistance material and coating. Exact inhibition mechanism is still in hypothesis until now. Inhibition mechanism once provided by inhibitor molecule that develops a barrier between the corrosive water phase and the metal surface. Most of the inhibitors currently used in producing wells are organic nitrogenous compounds. Dosage of inhibitor mainly based on the corrosivity of the environment (oil well, gas production, transport line). The efficiency of corrosion inhibitor shows a significant effect for lowering corrosion rate. European Federation of Corrosion (EFC) recommended a guideline for the application of corrosion inhibitor as follow:
- Key factors that affect performance:
> Inhibitor efficiency or reduction in corrosion rates;
> Solubility and oil/water partitioning behavior;
> Optimum concentration
> Film stability (flow conditions, temperature)
- Compatibility of the corrosion inhibitor with:
> The production fluids;
> Other chemicals;
> Downstream processing of produced fluids
> All materials in the injection and production systems (e.g elastomers, seals, liners);
- Environmental Issues (biodegradability, toxicity, bioaccumulation)
- Economic (cost, availability of products)
Cathodic Protection
Technology behind cathodic protection (CP) is based on simple principle as to minimize anodic dissolution by application cathodic current. Electrochemistry theory first significant application for cathodic protection was by Sir Humphrey Davy in 1761 for copper wooden ships. The first cathodic protection was applied by Robert J. Kuhn for oil and gas pipeline in New Orleans in 1928. The first cathodic protection standard was drawn in DIN 30676 in 1984. Design of cathodic protection demands accurate information of the nature of the corrosive medium, shape of the structures to be protected, and environment as described in Table 2.
Table 2 - Cathodic Protection design Codes
Deepwater Challenge
Development of offshore cathodic protection requires more detailed guidelines for deepwater platform because of CP design parameter (seawater salinity, dissolved oxygen, temperature, hydrostatic pressure, and presence of calcareous deposits) changes significantly in this depth. Available guidelines from NACE and DNV are applicable and approved for shallow water (<300 meters). Having similar oceanographic characteristic, Indonesian CP designer can share Gulf of Mexico offshore project experience which has reached 900 meter water depth, Figure 2.
Figure 2. Corrosion Protection offshore deepwater challenge
Hydrogen Embrittlement
Hydrogen embrittlement relatively is not a new phenomenon. The loss of ductility due to diffusion of evolved hydrogen from cathodic polarization lead to cracking when component experience load stress and or residual stress, referred as hydrogen induced stress cracking (HISC). The increase use of materials with less proven record in seawater cathodic protection environment has raised the profile of this degradation mechanism in recent years. Another difficulty of cathodic protection for subsea equipments and systems is due to the complexity of subsea component systems. Subsea component that have suffered this failures are: flowlines, manifold hub connector, instrumentation fitting, and circlip fastener. Susceptibility of HISC in several references associated with the effect of residual stress, material and microstructures, cathodic potential parameter (protection potentials and the choose of anodes).
Microstructural features of stainless steel that shall be controlled are: ferrite content, austenite spacing, and grain flow, as recommended in DNV RP F-11221. Resistance to HISC decreases in coarse aligned ferrite-austenite microstructure and or with the presence of third phases (nitrides, alpha prime e.g. in superduplex stainless 25Cr). Therefore more detailed microstructure assessment should incorporate for more accurate and valid results.
Safe cathodic protection design for high susceptibility of hydrogen embrittlement in sea water can be achieved by electrical solution by the use of diode as a potential buffer and by selecting alternative lower voltage of sacrificial anode.
CP System Maintenance
Maintenance of cathodic protection system is important to maintain the protective performance of the system to protected structures. Simple control point for review and maintenance of cathodic protection system are as follow:
- Monitoring of electrical system that include: electrical instruments (power supply, rectifier, transformer, cable connection)
- Monitoring of primary protective coating of the protected structures (pipelines, platform). E.g Pipe-to-soil Potential measurement. Any coating faults can make “overload” protection current. Therefore cathodic protection system should be review: e.g raise the coating breakdown factor ;
- Monitoring protected structure potential. Obtaining CP potential along the protected structures can be difficult in offshore pipelines, which requires diver-man or remote operated vehicle and wired or wireless potential measurement device.
Corrosion Monitoring and Inspection
The main purposes of corrosion monitoring and inspection are:
- Evaluation Purpose:
> Materials under service conditions;
> Control of the production process (periodic, integrated, online assessment);
- Information Basis:
> Material Selection;
> Life assessment (corrosion defect assessment, remaining strength assessment);
Corrosion monitoring for many years utilized for upstream and downstream oil and gas industry involving quite varying technology, from simple chemical coupon to sophisticated automatic inline inspection tools, Table 3. Data combining (fluid corrosivity, corrosion rate, coating fault, metal loss sizing) from these corrosion monitoring activity can be utilized further to assess the overall integrity of engineering structures against corrosion attack.
Table 3 - Corrosion Monitoring Techniques
Table 4 - Aboveground Inspection Tools
Corrosion Assessment
Output of corrosion assessment is a run-repair-replace decision. Methodology for corrosion assessment can be divided into two categories:
- Data evaluation – Information can be provided by inline inspection, NDT inspection, visual examination, and on-site mechanical testing;
- Data evaluation and detailed inspection. More recent direct assessment methodology from NACE and GTI are basically consists of data evaluation (historical data, detailed inspection data) and inspection (indirect inspection, direct examination)
Direct assessment becomes important choice for pipeline integrity management when inline inspection meets geometry restrictions or pressure testing become very expensive. Corrosion direct assessment methodologies and protocol published by NACE are:
- External Corrosion Direct Assessment by NACE RP 0502:2002
- Stress Corrosion Cracking Direct Assessment by NACE RP 0204: 2004
- Internal Corrosion Direct Assessment for Dry Gas will be NACE RP 0104:2005
- Internal Corrosion Direct Assessment for Wet Gas by NACE
Direct assessment (ECDA, ICDA, SSCDA) are typical four step process consists of: pre-assessment, indirect inspection, direct examination, and post-assessment. Simplified ECDA workflow can be seen in Figure 6. Effectiveness of these direct assessments in some references relatively varying. Southwest Research Institute reported that 85% anomalies inspected by inline inspection successfully predicted by dry gas ICDA. Most agree that for more accurate result, alternative validation must be considered as follow:
- NACE External Corrosion Direct Assessment should consider other inspection tools complimentary to tools in selection matrix (analog DCVG, CIPS, Soil Resistivity) ;
- NACE Internal Corrosion Direct Assessment should incorporate alternative probabilistic analysis (e.g. Mechanical Failure by Thacker, Risk Indexing System by Muhlbauer, First Order Reliability Method by Ahmamed and Melchers) to reduce bias from data uncertainty (e.g. the use of pipeline elevation profile map)
Figure 3 - External Corrosion Direct Assessment Work Flow by NACE and TGI
Related Post:
Corrosionomic: Economic Perspective of Iron Rusts and Scales
Corrosion Morphology
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