H2S Measurement Crude Oil Report

Measurement of

Hydrogen Sulfide

in Crude Oil

Author: Ian Mylrea

Date 10th

March 2014

Issue 1.1

Stanhope Seta,

London Street,

Chertsey,

United Kingdom

KT16 8AP

Tel. +44 1932 564391

www.stanhope-seta.co.uk

Stanhope Seta Ian Mylrea Page 2 of 15

Executive Summary

Crude oil samples from Bakken, North Dakota were tested by two methods. This was a very

successful experiment. Repeatability for the proposed Crude Oil Appendix to ASTM D7621/IP 570

Procedure A (with Vapor Phase Processor) was similar to the precision studies done for distillate and

marine residual fuels and is estimated to be 9%. A strong correlation was found between the liquid

phase results from ASTM D7621/IP 570 and the vapor phase results for a modified ASTM D5705

method.

There are practical advantages to doing the proposed test when compared to the modified ASTM

D5705: smaller test volume – which maintains the bulk material volume and headspace; faster – the

test can be completed in 25 minutes; the liquid phase result may allow a more precise stoichiometric

calculation of the amount of hydrogen sulfide scavenger to be estimated.

Caution: Storage container vapor phase hydrogen sulfide concentrations should not be used to

estimate liquid phase concentrations (and vice versa) as the vapor phase result depends on the

temperature, the headspace volume and container size and shape. The ASTM D7621/IP 570 liquid

phase results are independent of the container size, shape and the temperature.

Thanks and acknowledgements

We appreciate the contribution to this study by Intertek who allowed us to use their facilities,

provided the samples and carried out the measurements using their in house (modified) ASTM

D5705 procedure.

y = 0.015x

R² = 0.97

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D5705 Modified

Hydrogen Sulfide in Crude Oil -

vapor versus liquid phase measurement


Contents Executive Summary ............................................................................................................................. 2

Thanks and acknowledgements .......................................................................................................... 2

Introduction ........................................................................................................................................ 4

Background ......................................................................................................................................... 4

ASTM D7621/IP 570 Background ........................................................................................................ 5

Methods Modifications for Crude Oil Measurements ........................................................................ 7

Test Protocol ....................................................................................................................................... 7

Results ................................................................................................................................................. 9

Results Discussion ............................................................................................................................. 10

Appendix 1 ........................................................................................................................................ 12

ASTM D7621/ IP 570 Crude Oil Appendix Proposal .......................................................................... 13

References ........................................................................................................................................ 15


Introduction

The purpose of this study was to show that IP 570/ASTM D7621 can be modified to extend the range

to measure the concentration of hydrogen sulfide in stabilised crude oil. At the ASTM D02 meeting

at Tampa in December 2013, a study was proposed to compare a modified version of ASTM D5705

(Measurement of Hydrogen Sulfide in the Vapor Phase Above Residual Fuel Oils) with the proposed

Crude Oil Appendix to ASTM D7621/IP 570 (Determination of hydrogen sulfide in fuel oils – Rapid

liquid phase extraction method). The study would take place a suitable laboratory in the United

States of America which has access to typical samples of crude oil with applicable levels of hydrogen

sulfide.

Background

Hydrogen Sulfide can occur naturally in crude3. In addition to being toxic, hydrogen sulfide is highly

reactive and is responsible for corrosion of infrastructure such as pipelines and rail cars. The recent

increase in production of volatile crude oil in Wyoming, Colorado and North Dakota has lead to a

surge in demand for transportation by railcar as pipeline access was unavailable. In 2008

approximately 10,000 cars were transported by rail, compared to 400,000 in 20131. On May 5

th,

2013 a tank in Berthold, North Dakota was found with a sample measuring over 1200 ppm which is

an extremely hazardous level2.

Hydrogen sulfide is a volatile gas at room temperature with a vapor pressure of 252 psig (1740 kPa),

and a boiling point of -60oC. As such, if it is present in a sample then it normally can be found in both

the liquid and vapor spaces within a closed container at normal ambient temperature. It is worth

noting that not all the hydrogen sulfide can transfer to the vapor phase at once. A vapor liquid

equilibrium is achieved which depends on the temperature, how full the vapor space is and what

other volatile components of the crude oil sample are present. Typically a sample containing 70

mg/kg hydrogen sulfide in the liquid phase can give rise to 7000 ppmv in the vapor space above it3.

The concentration in the vapor space is typically measured using a colorimetric gas detector tube to

identify its presence and whether the level is hazardous.

Hydrogen sulfide can be removed by treatment with scavengers. Some scavengers work by reacting

with hydrogen sulfide to form other less harmful compounds. The scavenger dosage required is a

function of how much hydrogen sulfide is present in the liquid phase.

Earlier work in 2011 funded by the CCQTA4 showed that measurement of the hydrogen sulfide

concentration in crude oil was difficult. Since no standardised method for the measurement of

hydrogen sulfide in crude oil had been developed a variety of ‘modified’ test methods were

simultaneously trialled on a variety of crude oils and crude oil condensates. The report concluded

that results between methods did not agree. When examining the data in the report significant

differences and so far unexplained anomalies are present (GC results seemed to max out at around

70 to 80ppm; the titration method gave 0ppm when the other three methods showed hydrogen

sulfide was present; GC and titration gave 10’s of ppm in liquid whilst the vapor method showed

almost no hydrogen sulfide was present, which was supported by the modified ASTM D7621/IP 570

method. However, of the four methods two methods results did make basic sense when compared.

Whilst the actual values differed significantly the following trends were apparent: high hydrogen

sulfide in vapor predicted by D5705 gave relatively high liquid phase hydrogen sulfide by modified


ASTM D7621/ IP 570; low hydrogen sulfide in vapor predicted by D5705 gave relatively low liquid

phase hydrogen sulfide by modified ASTM D7621/ IP570.

Encouragement was provided in the executive summary to continue the work…”It is recommended

that the IP-570 for crude method continue to be developed under the direction and efforts of

Stanhope-Seta, and that the H2S in Crude Measurement Project participants individually continue to

support those efforts by providing access to field experience/expertise and crude petroleum samples

as required.”

Figure 1 Data provided by the Canadian Crude Quality Technical Association (CCQTA)

Sample

Result (ASTM

D5705)

Result (ASTM D7621/IP

570)

1 >2000 117

2 0.00 0.00

3 >2000 206

4 2.00 0.05

5 268.0 10.5

6 0.75 0.03

ASTM D7621/IP 570 Background

ASTM D7621/IP 570 was developed to measure hydrogen sulfide in marine fuels and blend streams

and was first standardised in 2009. The test method precision enabled specification writers to

include it in ISO 8217, the marine fuel specification, in 2010, with a maximum limit of 2.00 mg/kg

(liquid phase). A separate hydrogen sulfide in distillate grade marine fuels study was carried out in

2011 which was added to the test method scope. A study into potential interferences revealed that

mercaptans and sulphides could elevate the readings. Extensive research followed, which enabled

the vapor phase process to be developed and in 2012 IP 570 was standardised with a new

procedure, known as Procedure A (Vapor Phase Process). ASTM D7621 which is jointed with IP 570

had similar updates and is currently technically equivalent.

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ASTM D5705

Hydrogen Sulfide in Crude Oil -

measurement of vapor phase versus liquid phase


The method uses a hydrogen sulfide specific detector in conjunction with a cold vapor phase process

to separate hydrogen sulfide from potential interferences. This places the detectors peak signal for

hydrogen sulfide in a specific time frame, similar to chromatography column techniques. Inspection

of the graph produced not only shows the magnitude but also the time which the peak occurred,

giving enormous confidence that the measurement is really hydrogen sulfide. See Figure 2 Relative

Elution for Hydrogen Sulfide and Methyl Mercaptan using VPP & Figure 3 Typical H2S Analyser

output for Hydrogen Sulfide

Figure 2 Relative Elution for Hydrogen Sulfide and Methyl Mercaptan using VPP

Figure 3 Typical H2S Analyser output for Hydrogen Sulfide

A recent innovation in 2013 enabled the test method to employ a liquid phase hydrogen sulfide

standard with a 3 month shelf life, which enabled the accuracy and precision to be confirmed. Test

results obtained from a proficiency testing scheme which uses the standard show very close

agreement between reference values and consensus values. A standard was tested during the tests

of which this paper is the subject, and is discussed later on.

Following recent experiences, three successful round robin (ILS) studies, all with good precision and

extensive research into interferences, coupled with the earlier positive signs in the CCQTA

programme and industry need with the development of an increase in production in the USA, it was


decided to develop an appendix in the hydrogen sulfide test method to enable wider use for

measuring hydrogen sulfide in crude oil.

Methods Modifications for Crude Oil Measurements

ASTM D7621/ IP 570 Procedure A and ASTM D5705 were modified to cater for the high hydrogen

sulfide concentrations and high vapor pressures.

Figure 4 The test chamber for ASTM D7621/IP 570

ASTM D7621/IP 570 measurements were made with the sample at room temperature. Small sample

sizes such as 0.05 or 0.1mL were employed in order to extend the range of the detector. In addition

the 5 minute equilibrium time no longer applied.

ASTM D5705 measurements were carried out with the sample at 25oC (rather than 60

oC) due to the

volatile nature of the samples. Colorimetric gas detector tubes in the range from 1000 to 10000 ppm

(up to 1%) were used.

Test Protocol

Measurements by ASTM D7621/ IP 570 and ASTM D5705 were carried out within approximately 30

minutes of each other.

A 1 litre sample of crude oil from

North Dakota, supplied over 95% full

was gently turned end over end.

Approximately 500ml was placed in

a 1 litre glass bottle and the screw

cap applied. A 4 oz (125mL) glass

bottle was also filled to the top

(95%+). The 1 litre bottle was placed

in a 25oC water bath for 30 minutes.

During the 30 minutes one test was carried out on the H2S Analyser using the 4 oz bottle following

ASTM D7621/ IP 570. Attention to replacing the cap promptly after each test was given. After 30

minutes the modified ASTM D5705 procedure was used to determine the vapor space hydrogen

sulfide concentration of the 1 litre bottle. Another test on the H2S Analyser was carried out back to

back with the first from the 4 oz bottle. Effectively one test was done before and one after the ASTM

Figure 5 ASTM D5705 Apparatus and a crude oil sample


D5705 test. Occasionally a 3rd

test was done using the modified ASTM D7621/IP 570 to gather

additional data.

Once the results were available the sample was recombined into the original 1 litre bottle and

shaken to lower the hydrogen sulfide concentration. A second full test as described above was

carried out – that is the sample was turned gently end over end and then split into the two

containers, placed in a water bath and tested.

This procedure (split, measure, combine, shake) was employed using two different crude oil samples

and various levels to build up a picture of the repeatability for ASTM D7621/IP 570 and for the

relationship between the vapor phase test and the liquid phase test.


Results

The ASTM D7621/ IP 570 apparatus was verified as per the test method. Tests were then carried out

to determine whether the typical sample injection volumes were practical. Tests were conducted to

demonstrate repeatability for D7621 and also comparison with vapor phase numbers. It was not

always possible to do a D5705 test due to the volume of sample available. More detailed results can

be found in Appendix 1.

D5705 Modified ASTM D7621/IP 570 Appendix

Vapor Phase H2S

(mg/kg)

Liquid Phase H2S

(mg/kg)

Standard

Deviation

(mg/kg)

9000 146 6.4

7000 98 9.5

6000 81 4.4

2500 50 2.4

2500 39 0.1

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D5705 Modified

Hydrogen Sulfide in Crude Oil - vapor

measurement versus liquid phase

measurement


Results Discussion

The main comparison shows that the vapor and liquid results correlate well with R2 = 0.97. The vapor

liquid equilibrium is approximately 66, that is Liquid Phase H2S = 0.015 x Vapor Phase H2S. This is

typical when compared to previous estimates in the literature3, and is only applicable as a

relationship for this particular crude oil, the container proportions (headspace versus liquid space)

and temperature used.

Repeatability was only tested for ASTM D7621 since the sample volume available meant that two

ASTM D5705 tests could not be done at the same time. The average repeatability for ASTM D7621

was 9% (See Appendix 1).

During the initial tests with ASTM D7621/ IP 570 it was observed that the following were important…

1. Due to the low sample volumes, getting an accurate weight for the sample was critical. This

was achieved in practice making sure the balance was a 4 place balance, mounted on a

granite block, vibration free, and away from draughts with the doors closed as far as was

practical. The best way to achieve this was to place the pipette in a beaker as shown.

During the main study sample weights from 0.04 and 0.08g were achieved with good

repeatability, equating to 50 and 100 µL respectively.

2. The crude oil sample settled over time. This was observed with a sample which had been left

for 24 hours and as it was poured it gradually became less transparent and more opaque

towards the bottom of the container. As the samples were of low viscosity it was decided

during the tests that prior to the ASTM D7621 determination a sample should be gently

turned end over end two times before the sample was taken.

3. It was observed that when injecting the sample into the test chamber during the ASTM

D7621 tests that the pipette should not be released until it has been removed from the test

chamber to avoid drawing in hydrogen sulfide vapor into the pipette and reducing the

concentration in the test chamber.


4. The following table describes the most appropriate volume of charge for the ASTM D7621/

IP 570 Crude Oil Appendix

Hydrogen Sulfide (mg/kg) Sample volume type of device

0 to 10 mg/kg 5mL Syringe

10 to 20 mg/kg 1 or 2mL Syringe

20 to 100 0.1mL Positive Displacement Pipette

100 to 200 0.05mL Positive Displacement Pipette

above 200 0.025mL Positive Displacement Pipette5

5. The diluent oil used became very full of air during the 5 minutes equilibrium time mentioned

in ASTM D7621/IP 570 (11.3). The equilibrium time was not required as the test chamber

was at ambient and therefore this step was omitted during the testing.

Other observations were as follows…

6. Good stability of the samples over time was observed. Even severe shaking of the sample

and leaving open for a few minutes only seemed to change the value by a small amount.

(See tests F and H). However any attempt to blend with either a neutral diluent or zero

hydrogen sulfide crude oil was unsuccessful with the hydrogen sulfide being immediately

lost.

7. Not all hydrogen sulfide is purged during the D5705 tests. Effectively the value obtained by

this method will be a function of temperature (controlled at 60 oC normally or 25

oC for these

tests), headspace and time allowed for the equilibrium to form (3 minutes).


Appendix 1

Notes

Tests A, B, C, J and K were conducted following the test protocol i.e. in parallel by both methods.

Tests B final test (0.00 mg/kg) was an experiment to demonstrate that all the hydrogen sulfide is

measured during D7621. This is different to D5705 where the sample is in equilibrium with its vapor

and the liquid still contains high levels of H2S after the test. Tests D were carried out on the 1 litre

sample container prior to blending with a 0.00 mg/kg sample (to try to make 20 mg/kg). The tests

are useful to show potential repeatability. A D5705 test was not carried out. Test E was the

measurement of the subsequent blend. Unfortunately all the hydrogen sulfide had been removed. It

is quite likely that the sample containing 0.00 mg/kg had either a natural scavenger or applied

scavenger and reacted with the hydrogen sulfide on blending. Tests F and G were on previously

bottled samples which were approximately 60% full. It was not possible to carry out a D5705 as the

sample was too small, however the results are useful to estimate repeatability. Tests H was on one

of the same bottles as G and H after shaking to lower the levels. Again no D5705. Tests I were by a

different operator. No D5705. Test L was carried out to show the accuracy of the analyser when

measuring a hydrogen sulfide standard. The certified value was 3.04 mg/kg which compares very

well to the 3.21 mg/kg measured on the day.

Test

ASTM D7621

(Crude Oil

Appendix) Repeat

repeatability

max

Sample

Mass

Sample

Volume

ASTM

D5705

modified

(mg/kg) % (g) (µL) (ppmv)

A 141 1 0.038 50 9000

A 150 2 6.2 0.038 50

B 109 1 0.037 50 7000

B 92.8 2 0.038 50

B 92.2 3 17.1 0.041 50

B 0 n/a 0.041 50

C 83.8 1 0.04 50 6000

C 77.6 2 7.7 0.037 50

D 55.6 1 0.041 50

D 46.3 2 18.3 0.037 50

D 46.3 3 0.079 100

D 41.2 4 11.7 0.082 100

E 0 n/a 1.625 2000 0

F 74.3 1 0.076 100

F 75.6 2 1.7 0.081 100

G 82.6 1 0.079 100

G 81.6 2 1.2 0.08 100

H 63.9 1 0.08 100

H 54.9 2 15.2 0.078 100

I 52.8 1 0.074 100

I 58.6 2 10.4 0.071 100

J 48.4 1 0.076 100 2500

J 51.8 2 6.8 0.074 100 2500

K 39.4 1 0.078 100 2500

K 39.2 2 0.5 0.079 100 2500

L 3.21 1 4.644 5000 n/a

Average repeatability 8.8%


ASTM D7621/ IP 570 Crude Oil Appendix Proposal

APPENDIX

(Nonmandatory Information)

X1. Alternative procedure for the measurement of hydrogen sulfide in crude oil at room temperature

X1.1 This alternative procedure may be used to extend the scope and range of the apparatus to estimate the amount of hydrogen sulfide in crude oils. In this procedure the test vessel is located in a support bracket at room temperature. The vapor phase processor (Procedure A) is required for this procedure as vapor present in the crude oil can damage the detector and chemical interferences may be present (See A2.2).

X1.2 Apparatus

X1.2.1 Support bracket

X1.3 Procedure

X1.3.1 Prepare the apparatus as per Section 9 & 10 ASTM D7621/IP 570.

X1.3.2 Follow the steps in Section 11 for Procedure A with the following additions.

X1.3.2.1 Place the support bracket in the temperature controlled test vessel heating jacket. X1.3.2.2 Insert the test vessel in the support bracket and fit the input/output tubing, so that the test vessel is at room temperature. X1.3.2.3 Carefully invert the sample end over end two times to mix the sample. X1.3.2.4 The appropriate volume shall be determined by reference to Table X1.

NOTE 1— If it is suspected that the sample contains a large amount of volatile components such as butane then use 0.1ml sample size to prevent pressurization of the test vessel.

NOTE 2—A single mass can be entered rather than entering the mass before and after sample introduction if the balance is tared.

NOTE 3—This procedure is critically dependent on the weighing of the sample and injection of the sample into the sample test chamber. During sample injection avoid drawing sample vapors into the pipette before removing the pipette from the test chamber.


Expected H2S Concentration

Required Test Volume

Sample Introduction

0 to 10 mg/kg 5 mL Disposable syringe 10 to 20 mg/kg 2 mL Disposable syringe 20 to 100 mg/kg 0.1 mL Pipette 100 to 200 mg/kg 0.05mL Pipette Above 200 mg/kg 0.025mL Pipette

TABLE X1 Appropriate Test Volume for Expected H2S Concentration

X1.4 Precision

A small repeatability study on samples with different hydrogen sulfide levels in the range 0 to 150 mg/kg was carried out which gave an average repeatability of 9%.


References

1 New York Times, January 25

th , 2014: Accidents surge as oil industry takes the train, by Clifford Krauss and Jad

Mauawad 2 Reuters News Agency, May 15

th 2013: Enbridge may shut Bakken oil rail terminal in sulfide gas dispute, by

Jeanine Prezioso 3 Crude Oils Their Sampling, Analysis and Evaluation, Harry N Giles & Clifford O. Mills

4 Canadian Crude Quality Technical Association Hydrogen Sulfide in Crude Measurement Report – Bill Lywood

& Dave Murray, March 2012 5 The Gilson Microman positive displacement pipette was used during the study and found to be suitable

Documents

H2S Measurement Crude Oil Report