Test uid
Sulphur (%, ICP)
TAN (mg KOH/g)
Crudes oil / region Venezuela Venezuala D iluted Persian Gulf
API 16.0 17.3 18.9 21.1 21.1 22.1 23.5 29.7 30.9 33.8 38.8 45.3 57.8
Volatile P, ppm
1.35 1.55 0.7
1.58 1.94 3.1
HGVO-1 US re nery HGVO-2 US re nery CDU residue - Asian re nery
0.705 0.391 0.515 0.992 0.161 0.409 0.669 1.201 1.216 2.303 1.477 1.229 1.623
40
Mexican Chad
Egypt Iraq
30
Persian Gulf Iran 1
20
Iran 2 UAE
Kazakhstan Qatar
10
% P contribution
0
HVGO-1 US re nery
HVGO-2 US re nery
CDU residue Asian re nery
12% Predator <
No treatment
Low-P multifunctional naphthenic acid corrosion inhibitor (Predator*)
Figure 5 RCA – corrosion studies of the field samples
Crude feedstock > 88%
the previously described RCA corrosion study (310ºC tem- perature, ~30 Pa shear stress) (see Figure 5 ). Despite the presence of a significant level of sulphur compounds in the test fluids, it is possible for the high-temperature and high- shear stress conditions to disrupt the protective iron sulphide layer and cause sulphidic corrosion. This increased corrosion was observed on the test metal coupons in the absence of treatment. However, the application of the new low-P multi- functional CI treatment (Predator * ) was able to mitigate the corrosion, achieving greater than 70% inhibition. Mitigation of downstream impact from phosphorus and other contaminants During the refining process of high-acid crudes, it is antic - ipated that naphthenic acid corrosion products, along with the dislodgement of protective iron sulphide and phos- phate layers, may result in fouling of the heat exchangers, atmospheric and vacuum distillation unit trays, and pump- around sections.6 Furthermore, these corrosion products may potentially contaminate and deactivate catalysts in the catalytic conversion unit. In the case of fouling due to the presence of phospho- rus, the source of phosphorus is typically not only from the naphthenic acid treatment chemistries. However, a majority of phosphorus concentration may originate from crude oil feedstock (including upstream additives), imported feeds,
lube oil wastes, and gasoline slop tanks. A field study was conducted at an Asian refinery where severe fouling occurred on the distillation trays in the heavy kerosene boiling range. The deposit analysis indicated a high level of phosphorus. The crude slate was tested for total phospho- rus and volatile phosphorus, and the results showed that more than 88 wt% of the total phosphorus content of the deposit was attributable to the crude feedstock (see Figure 6 ). As for the phosphorus contribution from the corrosion inhibitor treatment, it was assumed that all of the phos- phorus from the chemistry was carried over into the heavy kerosene boiling range. Despite this conservative assump- tion, the phosphorus contribution from the inhibitor was less than 12 wt%. Contaminants other than phosphorus, such as silica, sodium, calcium, arsenic, lead, nickel, vanadium, iron and more, are also commonly found in crude and other feed- stock. These can be potential contaminants, poisons, and foulants for the hydrotreater and other downstream units.7 It is recognised that fouling and catalyst poisoning Figure 6 Phosphorus contribution from crude oil feedstock vs corrosion inhibitor
Hydrotreater feedstock characterisation 1
Average test value for
Approx. molar ppm level in light gasoil
Parameter
Unit
Naphtha
heavy naphtha
Kerosene
Light gasoil
TAN
mg KOH/g
0.05
0.12
0.16
0.13
570 410 530 730 340
Basic N
ppm N
9
42 16 46
10
24 15 61
Br #
g Br₂/100 g
17 50
9
230,000
CO SH
ppm ppm ppm wt%
54
203
265
217
100
Pyrrole
5
5
7
95
S
0.18
0.2
0.41
0.78
59,000
Table 1
13
PTQ Q2 2025
www.digitalrefining.com
Powered by FlippingBook