Prediction of Corrosion Inhibitor Performance Using Simulated CO2/H2S Environmental Autoclave and Flowloop Tests

Abstract:

The hot topic series describes a test program and the result targeted towards evaluating corrosion inhibitor performance in CO2/H2S environments. After preliminary screening of the inhibition characteristics and performance of 5 corrosion inhibitors (designated A,B,C,D & E) under simulated CO2/H2S environment in a high temperature, high pressure flowing autoclave, the best two corrosion inhibitors (corrosion inhibitors A & B) were selected for further flow loop testing under simulated North Sea pipeline service conditions.

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Overview
This hot topic series describes a test program and the results targeted towards evaluating corrosion inhibitor performance in CO₂/H₂S environments. After preliminary screening of the inhibition characteristics and performance of 5 corrosion inhibitors (designated A, B, C, D, & E) under simulated CO₂/H₂S environment in a high temperature, high pressure flowing autoclave, the best two corrosion inhibitors (corrosion inhibitors A & B) were selected for further flow loop testing under simulated North Sea pipeline service conditions.
The worst case pipeline service conditions (90% synthetic field brine/10% hydrocarbon (depolarized kerosene) environment with H₂S (partial pressure 0.075 psia [0.5 KPa]) and CO2 (partial pressure 75 psia [0.5 MPa]) were simulated at 300 F. (149 C.) in a laboratory flowloop and the performance of the selected corrosion inhibitor formulations A & B on API 5L X-65 carbon steel and 0.5 percent Cr X-65 steel were evaluated at two concentrations (100 ppm and 250 ppm by volume).
The corrosion rates were monitored at stirred (reservoir), laminar and turbulent flow regimes at wall shear stresses corresponding to a range of velocities (4.2, 5.3, 6.3, 7.0, 7.9, 13.1, 15.4, 17.4 and 21.1 ft/sec) using linear polarization (LPR) and weight loss techniques.
The test results indicated the following:

Provided the proper concentration of corrosion inhibitor is applied continuously, carbon steel can be satisfactorily inhibited under laboratory test conditions that simulate pipeline worst case corrosion conditions.
Corrosion inhibitor "B" was not as effective as corrosion inhibitor "A" requiring about 2.5 times as much "B" as "A" to accomplish the same level of corrosion control under these simulated laboratory test conditions.
The results of this corrosion inhibitor evaluation program do not support the use of 0.5 Cr X-65 material over X-65.
The flowloop test data obtained at higher wall shear stresses indicated, within the limits of the wall shear stress parameters, there was little or no effect on the corrosion inhibitor film being laid down continuously on the metal surface.

Introduction
The results presented in this hot topic are the second phase of a study performed to evaluate the feasibility of using inhibited carbon steel rather than duplex steel as a major material of construction in a proposed North Sea pipeline.
In the first phase of this study, the results of high temperature-high pressure flowing autoclave tests established that it was possible for commercially available corrosion inhibitors to be thermally stable at 300 F. (149 C.) as well as provide >90 percent corrosion inhibition to carbon steels (X-65 and 0.5% Cr enhanced X-65) under laboratory test conditions simulating conditions predicted for the proposed North Sea pipeline (see Tables 1 and 2).
In this hot topic the results of the Phase 2 studies are reported. In this study, the two best performing corrosion inhibitors from Phase 1 were tested in a flow loop apparatus to evaluate their performance under varying conditions of flow over a longer period of time. The performance of these two corrosion inhibitors was determined on both X-65 and 0.5% Cr enhanced X-65 specimens at inhibitor concentrations of 250 and 100 ppm. Data was measured for static, laminar and impingement flow conditions.
Maximum flow conditions for the flowloop tests were established at 10 ft/sec based on a flow regime calculated using the Briggs and Brill (B-B)¹, as well as the Taitel-Dukler (T-D) models. The Briggs and Brill model predicted the occurrence of intermittent slugs with a liquid film velocity of 6.2 ft/sec. On the other hand, the Taitler-Dukler model, which is considered by the authors to be more representative, indicated annular flow and no slug flow in the pipeline. A velocity of 10 ft/sec liquid velocity was selected as a very conservative flow rate parameter for the flow loop tests. The wall shear stress (t) due to a liquid flow velocity, v, in the field pipeline was calculated as follows:

t= frn²/2

where r= density of the liquid and f = friction factor
The liquid flow rate in the laboratory flow loop corresponding to the above shear stress value was calculated using the above equation and Moody diagrams which provide relationships between pipe diameter (D) and roughness factor (e/D) and f, e/D, and Reynolds number (Re = D/??; ??= viscosity of the liquid.)
The effect of flow rate on the inhibitor film was studied using the flow loop apparatus at up to nine (9) flow rates corresponding to 40%, 60%, 80%, 100%, 120%, 330%, 456%, 660% and 865% of the maximum (100%) anticipated North Sea pipeline wall shear stress value using a velocity of 10 ft/sec (Table 3). Other flowloop test parameters included were: 300 F. (149 C.); pp CO₂ of 75 psia; pp H₂S of 0.075 psia; 90% Synthetic North Sea Pipeline brine (Table 4); 10% depolarized kerosene. These test parameters represented worst case senario for the proposed North Sea pipeline.
Prior to initiation of the Phase 2 study, flow loop apparatus performance was tested using the BP Protocol Calibration Test. The flow loop test apparatus encountered no problems passing the require calibration test criteria.
The chemical supplier of the two corrosion inhibitors to be evaluated in the flow loop test, provided preliminary flowloop test data developed in their laboratory. The test parameters used were: 180 F. (82 C.); pp CO₂ of 70 psia; X-65 carbon steel specimens; 70% synthetic North Sea pipeline brine; 30% depolarized kerosene; flowrate - 2.2 ft/sec. These flowloop test conditions were less rigorous than the Phase 2 flowloop test conditions. However, the test results were in line with the performance indicated in the Phase 1 tests.
Both the BP Protocol Calibration Test results and the chemical supplier's flowloop test results tend to add support and credibility to the results reported in study.

Table 1

HT-HP Autoclave Tests

Corrosion Inhibitors Evaluations

Table 2

HT-HP Autoclave Tests

Corrosion Inhibitors Evaluations

Table 3

North Sea Pipeline Flowloop Test

Corrosion Inhibitor Evaluation - Flow Regime Data

Note: Tau [wall shear stress} value calculations based on a velocity of 10 ft/sec
Calculated Data - Flowloop Apparatus

Percent TAU	TAU Pa	TAU Lbs/sq/ft	RHO [Kg/cu.m.]	I.D. [cm]	Velocity [m/s]	MU [poise]	Reynolds No. Re	Friction factor [f]	Velocity [ft/sec]	Flow Rate [gpm]
100	41.78	0.872	967.61	1.27	2.13	0.002825	92738	0.019	6.99	4.28
40	16.71	0.349	967.61	1.27	1.28	0.002825	55790	0.021	4.21	2.58
60	25.07	0.523	967.71	1.27	1.61	0.002825	70016	0.02	5.28	3.23
80	33.42	0.698	967.71	1.27	1.91	0.002825	82947	0.019	6.26	3.83
120	50.14	1.047	967.71	1.27	2.4	0.002825	104373	0.018	7.87	4.82

Table 4

SYNTHETIC BRINE COMPOSITION

North Sea Synthetic Brine Composition

Constituent	Desired Mixture - mg/L	Actual Mixture - mg/L
Sodium - Na	20,000	20,835.30
Calcium - Ca	2,000	2,000.00
Magnesium - Mg	1,500	1500.4
Barium - Ba	50	50
Chloride - Cl	40,000	39,994.90
Sulfate - SO₄	20	20
Bicarbonate - HCO₃	100	100.3

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