API RP 581 - 3rd Ed.2016 - Add.2-2020 - Risk-Based Inspection Methodology

RISK-BASED INSPECTION METHODOLOGY, PART 2, ANNEX 2.B—DETERMINATION OF CORROSION RATES 2.B-103
2.B.13 CO 2 Corrosion
2.B.13.1
Description of Damage
Carbon dioxide is a weakly acidic gas. In streams with carbon dioxide and free water, the CO 2 dissolves in water
producing carbonic acid (H 2 CO 3 ). The carbonic acid then dissolves the steel producing iron carbonate and
hydrogen (Fe+H 2 CO 3 →FeCO 3 +H 2 ). Despite being a weak acid, carbonic acid can be extremely corrosive to
carbon steel. CO 2 is commonly found in upstream sections before treatment. CO 2 corrosion requires the
presence of free water in order to produce the Carbonic acid. The primary variables that influence CO 2 corrosion
rates are the CO 2 concentration, operating pressure, operating temperature, application of inhibitors, flow rate,
and presence of hydrocarbon fluids, and contaminants in the system.
Aqueous CO 2 corrosion of carbon and low alloy steels is an electrochemical process involving the anodic
dissolution of iron and the cathodic evolution of hydrogen. The electrochemical reactions are often accompanied
by the formation of films of FeCO 3 (and/or Fe3O 4 ), which can be protective or non-protective depending on the
conditions under which these are formed.
NORSOK Standard M-506 has been used as the main reference for the developing the corrosion rate
calculation model described in this section.
2.B.13.2
Basic Data
The data listed in Table 2.B.13.1 are required to determine the estimated corrosion rate for carbonic acid
service. If precise data have not been measured, a knowledgeable process specialist should be consulted.
Entering only the data marked required will result in a conservative estimate of the corrosion rate. The
calculation for the corrosion rate is more refined as more optional data are entered.
2.B.13.3
2.B.13.3.1
Determination of Corrosion Rate
Calculation of the Corrosion Rate
The steps required to determine the corrosion rate are shown in Figure 2.B.13.1. The corrosion rate may be
determined using the basic data in Table 2.B.13.1 in conjunction with Equation (2.B.23).
CR = CR ⋅min
⎡
⎣
F , F
B glycol inhib
⎤
⎦
(2.B.23)
The calculation of the base corrosion rate, CR B , is most complex; it depends on the temperature, the partial
pressure of CO 2 , the fluid flow velocity, and the pH of the fluid. The following paragraphs detail how these
can be estimated for RBI purposes for some simple mixtures of crude oil, water, and natural gas mixtures. In
order to estimate corrosion rates for situations outside this simple mixture, the analyst should refer to
NORSOK Standard M-506. In cases where the equipment is not associated with upstream production, the
analyst should also be prepared to adjust or estimate corrosion rates for fluids that are not mixtures of crude,
water and natural gas.
2.B.13.3.2
Relative Humidity
In order for corrosion to occur, there must be liquid water present in the equipment. In a system transporting
gas, liquid water exists only if the temperature is below the dew point and the relative humidity in the stream
is greater than 100 %. When a mixture of water vapor and natural gas behaves approximately as ideal
gases, the relative humidity in a gas is 100 % when the partial pressure of the water vapor is equal to the
saturation pressure. This result in the simplified formula for the relative humidity,
⎛ x⋅ P ⎞⎛ 1 ⎞
RH = ⎜
P T
⎟⎜ ⎟
⎝ ⎠ ⎝ 0. 622 + x ⎠
sat
( )
(2.B.24)