API RP 581 - 3rd Ed.2016 - Add.2-2020 - Risk-Based Inspection Methodology
2.B-108 API RECOMMENDED PRACTICE 5812.B.13.5TablesTable 2.B.13.1—CO 2 Corrosion—Basic Data Required for AnalysisBasic DataTemperature—RequiredPressure—RequiredCommentsThe corrosion phenomenon is highly temperature dependent. Themaximum temperature of the process is required. Temperaturesabove 140 °C (284 °F) are not considered.Total pressure of the system. The total pressure of the gas is a bigcontributor in the corrosion rate up to about 250 psig.CO 2 concentration (mole %)—Required Determine the CO 2 partial pressure (p CO2 ) = (mol fraction of CO 2 ×total pressure), a maximum 4 MPa (580 psi) partial CO 2 pressure isconsidered.p CO2 —Required, if CO 2 concentration isnot givenMaterial of construction—RequiredpH—RequiredStream properties: bulk density, ρ m ,viscosity, μ m , gas to liquid ratios—RequiredFor systems with liquids:Water cut—OptionalFor gas systems: Relative humidity, RHor the dew point temperature, T d —OptionalGlycol/water mix—OptionalInhibition efficiency—OptionalCO 2 partial pressure, which is converted to CO 2 fugacity to accountfor non-ideal behavior.Determine the material of construction of equipment/piping. Stainlesssteels and copper alloys are assumed to be resistant to CO 2corrosion.If known explicitly, the pH of the stream should be used; otherwiseEquations (2.B.27), (2.B.28), and (2.B.29) can be used to estimate thepH based on the CO 2 partial pressure, whether the water in the streamis Fe ++ saturated or water with salinity slightly larger than seawater.Guidance with respect to typical values properties expected in naturalgas–oil mixtures (i.e. reservoir fluids) is provided. Estimation ofdensities can be made on the basis of the oil density (°API), gas–oilratio (GOR), pressure, P, and temperature, T. For other streams, aprocess engineer should assess these parameters.Determine the percentage of water in the system. The default for thisfield is 30 %.Determine the dew point temperature, T d , based on the water content.Equation (2.B.25) is provided for guidance, but should not beassumed to be accurate within ±10 °F. If not provided, the gas streamtemperature is assumed to below the dew point.Water content of glycol/water mix in %weight (%water in the totalglycol/water mix). The default value would assume no glycol added inthe system.Requires %efficiency of the inhibitor. No inhibitor injected as a defaultvalue.
RISK-BASED INSPECTION METHODOLOGY, PART 2, ANNEX 2.B—DETERMINATION OF CORROSION RATES 2.B-109Table 2.B.13.2—pH Temperature FunctionTemperature(°F)pH3.5 4.0 4.5 5.0 5.5 6.0 6.568 6.00 5.45 4.9 3.72 2.55 1.55 0.7286 8.52 7.77 7.02 5.16 3.40 2.00 0.91104 10.98 10.06 9.13 6.49 4.08 2.30 1.02122 11.92 10.96 10.01 6.86 4.10 2.20 0.94140 12.83 11.86 10.89 7.18 4.05 2.03 0.84158 13.42 12.01 10.6 6.58 3.61 1.86 0.87176 13.93 12.12 10.31 6.01 3.20 1.70 0.90194 9.37 7.91 6.45 2.44 0.82 0.49 0.32212 9.23 8.04 6.38 2.19 0.94 0.62 0.42230 8.96 8.09 6.22 1.87 1.07 0.77 0.53248 8.55 8.06 5.98 1.48 1.20 0.92 0.65266 7.38 6.39 3.98 0.96 0.80 0.63 0.47284 6.26 4.91 2.31 0.53 0.46 0.39 0.32302 5.20 3.62 0.98 0.19 0.19 0.19 0.19Table 2.B.13.2M—pH Temperature FunctionTemperature(°C)pH3.5 4.0 4.5 5.0 5.5 6.0 6.520 6.00 5.45 4.9 3.72 2.55 1.55 0.7230 8.52 7.77 7.02 5.16 3.40 2.00 0.9140 10.98 10.06 9.13 6.49 4.08 2.30 1.0250 11.92 10.96 10.01 6.86 4.10 2.20 0.9460 12.83 11.86 10.89 7.18 4.05 2.03 0.8470 13.42 12.01 10.6 6.58 3.61 1.86 0.8780 13.93 12.12 10.31 6.01 3.20 1.70 0.9090 9.37 7.91 6.45 2.44 0.82 0.49 0.32100 9.23 8.04 6.38 2.19 0.94 0.62 0.42110 8.96 8.09 6.22 1.87 1.07 0.77 0.53120 8.55 8.06 5.98 1.48 1.20 0.92 0.65130 7.38 6.39 3.98 0.96 0.80 0.63 0.47140 6.26 4.91 2.31 0.53 0.46 0.39 0.32150 5.20 3.62 0.98 0.19 0.19 0.19 0.19
- Page 287 and 288: RISK-BASED INSPECTION METHODOLOGY,
- Page 289 and 290: RISK-BASED INSPECTION METHODOLOGY,
- Page 291 and 292: RISK-BASED INSPECTION METHODOLOGY,
- Page 293 and 294: RISK-BASED INSPECTION METHODOLOGY,
- Page 295 and 296: RISK-BASED INSPECTION METHODOLOGY,
- Page 297 and 298: RISK-BASED INSPECTION METHODOLOGY,
- Page 299 and 300: RISK-BASED INSPECTION METHODOLOGY,
- Page 301 and 302: RISK-BASED INSPECTION METHODOLOGY,
- Page 303 and 304: RISK-BASED INSPECTION METHODOLOGY,
- Page 305 and 306: RISK-BASED INSPECTION METHODOLOGY,
- Page 307 and 308: RISK-BASED INSPECTION METHODOLOGY,
- Page 309 and 310: RISK-BASED INSPECTION METHODOLOGY,
- Page 311 and 312: RISK-BASED INSPECTION METHODOLOGY,
- Page 313 and 314: RISK-BASED INSPECTION METHODOLOGY,
- Page 315 and 316: RISK-BASED INSPECTION METHODOLOGY,
- Page 317 and 318: RISK-BASED INSPECTION METHODOLOGY,
- Page 319 and 320: RISK-BASED INSPECTION METHODOLOGY,
- Page 321 and 322: RISK-BASED INSPECTION METHODOLOGY,
- Page 323 and 324: RISK-BASED INSPECTION METHODOLOGY,
- Page 325 and 326: RISK-BASED INSPECTION METHODOLOGY,
- Page 327 and 328: RISK-BASED INSPECTION METHODOLOGY,
- Page 329 and 330: RISK-BASED INSPECTION METHODOLOGY,
- Page 331 and 332: RISK-BASED INSPECTION METHODOLOGY,
- Page 333 and 334: RISK-BASED INSPECTION METHODOLOGY,
- Page 335 and 336: RISK-BASED INSPECTION METHODOLOGY,
- Page 337: RISK-BASED INSPECTION METHODOLOGY,
- Page 341 and 342: RISK-BASED INSPECTION METHODOLOGY,
- Page 343 and 344: RISK-BASED INSPECTION METHODOLOGY,
- Page 345 and 346: RISK-BASED INSPECTION METHODOLOGY,
- Page 347 and 348: RISK-BASED INSPECTION METHODOLOGY,
- Page 349 and 350: CONTENTSOVERVIEW ..................
- Page 351 and 352: 2.C-2 API RECOMMENDED PRACTICE 581D
- Page 353 and 354: 2.C-4 API RECOMMENDED PRACTICE 5812
- Page 355 and 356: 2.C-6 API RECOMMENDED PRACTICE 581e
- Page 357 and 358: 2.C-8 API RECOMMENDED PRACTICE 5812
- Page 359 and 360: 2.C-10 API RECOMMENDED PRACTICE 581
- Page 361 and 362: 2.C-12 API RECOMMENDED PRACTICE 581
- Page 363 and 364: 2.C-14 API RECOMMENDED PRACTICE 581
- Page 365 and 366: 2.C-16 API RECOMMENDED PRACTICE 581
- Page 367 and 368: 2.C-18 API RECOMMENDED PRACTICE 581
- Page 369 and 370: 2.C-20 API RECOMMENDED PRACTICE 581
- Page 371 and 372: 2.C-22 API RECOMMENDED PRACTICE 581
- Page 373 and 374: 2.C-24 API RECOMMENDED PRACTICE 581
- Page 375 and 376: 2.C-26 API RECOMMENDED PRACTICE 581
- Page 377 and 378: PART 3CONSEQUENCE OF FAILURE METHOD
- Page 379 and 380: 4.6.5 Releases to the Environment .
- Page 381 and 382: 5.9.7 Determination of Final Toxic
- Page 383 and 384: 3-2 API RECOMMENDED PRACTICE 581[7]
- Page 385 and 386: 3-4 API RECOMMENDED PRACTICE 581d)
- Page 387 and 388: 3-6 API RECOMMENDED PRACTICE 5813.9
2.B-108 API RECOMMENDED PRACTICE 581
2.B.13.5
Tables
Table 2.B.13.1—CO 2 Corrosion—Basic Data Required for Analysis
Basic Data
Temperature—Required
Pressure—Required
Comments
The corrosion phenomenon is highly temperature dependent. The
maximum temperature of the process is required. Temperatures
above 140 °C (284 °F) are not considered.
Total pressure of the system. The total pressure of the gas is a big
contributor in the corrosion rate up to about 250 psig.
CO 2 concentration (mole %)—Required Determine the CO 2 partial pressure (p CO2 ) = (mol fraction of CO 2 ×
total pressure), a maximum 4 MPa (580 psi) partial CO 2 pressure is
considered.
p CO2 —Required, if CO 2 concentration is
not given
Material of construction—Required
pH—Required
Stream properties: bulk density, ρ m ,
viscosity, μ m , gas to liquid ratios—
Required
For systems with liquids:
Water cut—Optional
For gas systems: Relative humidity, RH
or the dew point temperature, T d —
Optional
Glycol/water mix—Optional
Inhibition efficiency—Optional
CO 2 partial pressure, which is converted to CO 2 fugacity to account
for non-ideal behavior.
Determine the material of construction of equipment/piping. Stainless
steels and copper alloys are assumed to be resistant to CO 2
corrosion.
If known explicitly, the pH of the stream should be used; otherwise
Equations (2.B.27), (2.B.28), and (2.B.29) can be used to estimate the
pH based on the CO 2 partial pressure, whether the water in the stream
is Fe ++ saturated or water with salinity slightly larger than seawater.
Guidance with respect to typical values properties expected in natural
gas–oil mixtures (i.e. reservoir fluids) is provided. Estimation of
densities can be made on the basis of the oil density (°API), gas–oil
ratio (GOR), pressure, P, and temperature, T. For other streams, a
process engineer should assess these parameters.
Determine the percentage of water in the system. The default for this
field is 30 %.
Determine the dew point temperature, T d , based on the water content.
Equation (2.B.25) is provided for guidance, but should not be
assumed to be accurate within ±10 °F. If not provided, the gas stream
temperature is assumed to below the dew point.
Water content of glycol/water mix in %weight (%water in the total
glycol/water mix). The default value would assume no glycol added in
the system.
Requires %efficiency of the inhibitor. No inhibitor injected as a default
value.