Page 271 - Pipeline Risk Management Manual Ideas, Techniques, and Resources

121248 Offshore Pipeline Systems
In the scoring system presented here, points are usually might cause condensation of entrained liquids, further adding
assigned to conditions and then added to represent the corro- to the amount of free, corrosive liquids. Liquids will gravity
sion threat. This system adds points for safer conditions. As flow to the low points of the line, causing corrosion cells in low-
noted in Chapter 4, an alternative scoring approach, which may lying collection points.
be more intuitive in some ways, is to begin with an assessment Inhibitors are commonly used to minimize internal corro-
of the threat level and then consider mitigation measures as sion (see Chapter 4). Generally, it is difficult to completely
adjustment factors. In this approach, the evaluator might wish eliminate corrosion through their use. Challenges are even
to begin with arating of environment-ither atmosphere type, more pronounced in two-phase or high-velocity flow regimes.
product corrosivity, or subsurface conditions. Then, multipliers Any change in operating conditions must entail careful evalua-
are applied to account for mitigation effectiveness. tion of the impact on inhibitor effectiveness. Other preventive
measures that can be credited in the assessment include the use
of probes and coupons, scale analysis (product sampling),
A. Atmospheric corrosion (weighting: lO0/o) inhibitor residual measurements, dewpoint control, monitoring
AI. Atmospheric exposures (weighting: S%) of critical points by ultrasonic wall thickness measurements,
and various pigging programs.
Portions of offshore pipelines often are exposed to the atmos- Score the product corrosivity and internal protection items
phere on platforms or onshore valve stations. Where such com- as described in Chapter 4.
ponents exist in the section being evaluated, score this item as
described in Chapter 4. BI. Product corrosivity (weighting: 10%)
B2. Internalprotection (weighting: 10%)
A2. Atmospheric type (weighting: 2%)
C. Submerged pipe corrosion (weighting: 70%)
The offshore environment is among the harshest in terms of
corrosion to metal. Humid, salty, and often hot conditions Offshore pipelines will be exposed to water, soil, or both. There
promote the oxidation process. In addition, some platfoms are many parallels between this environment and the subsur-
where pipeline components are exposed to the atmosphere pro- face (soil) environment discussed in Chapter 4.
duce additional chemicals to accelerate corrosion. Score as The scoring for this portion of the corrosion index closely
described in Chapter 4. follows the onshore risk assessment model. The threat is evalu-
ated by assessing the corrosivity of the pipeline’s environment
A3. Atmospheric coating (weighting: 3%) and then the effectiveness of the common mitigation measures
cathodicprotection and coating.
Coating is a most critical aspect of the atmospheric corrosion
potential. Score this item as detailed in Chapter 4. C1. Submergedpipe environment (weighting: 20%)

B. Internal corrosion (weighting: 20%) In this item, distinctions between the corrosive potential of
various electrolytes can be considered. In the case of offshore
Internal corrosion, caused by corrosiveness of the product systems, the electrolyte is usually a highly ionic water (saltwa-
inside the pipeline, is a common threat in offshore hydrocarbon ter or brackish water) that is very conducive to corrosion of
pipelines. Hydrocarbon production usually involves the pro- metals. It is often appropriate to score all sections as low resis-
duction of several components such as oil, gas, water, and vari- tivity (high corrosion potential) as described in Chapter 4.
ous impurities. While pure hydrocarbon compounds are not From an electrolyte standpoint, differences between buried
corrosive to steel, substances such as water, CO,, H,S, which and unburied conditions might be minimal and quite change-
are intentionally or unintentionally transported, provide a cor- able because of shifting sea bottom conditions-pipelines
rosive environment inside the pipe. Until recently, separation of are often covered and uncovered periodically by shifting
these components occurred offshore, where waste streams were sea bottom conditions. It is also conservative to assume that
easily (and in an environmentally unsound manner) disposed burial soils will also have a high ionic content because of the
of. As such practices are discontinued, pipelines designed to entrainment of saltwater. Differences between water condi-
transport a single phase component (either oil or gas), after off- tions might also be minimal. However, changes in electrolyte
shore product separation had occurred, now are called on to oxygen content, temperature, and resistivity might be
transport un-separated product streams to shore where separa- anticipated with resulting changes in cathodic protection
tion and disposal is more economical, The increased chance for effectiveness and corrosion potential. When distinctions are
internal corrosion from the now common practice of transport- appropriate, the evaluator can consider such factors to score
ing un-separated production as a multiphase mixture must be different environments.
considered.
It is not uncommon for an offshore line to experience a Mechanical corrosion As with onshore pipelines, the poten-
change in service as new wells are tied in to existing pipelines tial for corrosion that involves a mechanical component should
or the product experiences changes in composition or tempera- be addressed in the risk assessment. Erosion is apotential prob-
ture. While an internal corrosive environment might have been lem in some production regimes. Production phenomena such
stabilized under one set of flowing conditions, changes in those as high velocities, two-phase flows, and the presence of sand
conditions may promote or aggravate corrosion. Liquids settle and solids create the conditions necessary for damaging ero-
as transport velocity decreases. Cooling effects of deeper water sion. Stress corrosion cracking (SCC) can occur when stress