Measurement ofHydrogen 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 shape and the temperature. faster – the test can be completed in 25 minutes. 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%. the headspace volume and container size and shape. .97 120 100 80 60 40 20 0 0 2000 4000 6000 8000 10000 D5705 Modified 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. The ASTM D7621/IP 570 liquid phase results are independent of the container size. North Dakota were tested by two methods. Hydrogen Sulfide in Crude Oil vapor versus liquid phase measurement D7621 Crude Oil Appendix 140 y = 0.Stanhope Seta Ian Mylrea Page 2 of 15 Executive Summary Crude oil samples from Bakken. 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. Thanks and acknowledgements We appreciate the contribution to this study by Intertek who allowed us to use their facilities. the liquid phase result may allow a more precise stoichiometric calculation of the amount of hydrogen sulfide scavenger to be estimated. 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. This was a very successful experiment. provided the samples and carried out the measurements using their in house (modified) ASTM D5705 procedure.015x R² = 0. ................................Stanhope Seta Ian Mylrea Page 3 of 15 Contents Executive Summary.................. 12 ASTM D7621/ IP 570 Crude Oil Appendix Proposal ........................................................................................ 13 References .................. 7 Results ............................................................................................................................................................................................................................ 4 ASTM D7621/IP 570 Background ............................ 2 Thanks and acknowledgements ............................................................................... 7 Test Protocol .......................................................................................................................................................................................................................................................................................................................................................................................................................... 15 ........................................................... 2 Introduction ........................................................................................... 10 Appendix 1 ........................ 5 Methods Modifications for Crude Oil Measurements ............................................................................................................................................................................................................. 4 Background ....... 9 Results Discussion ......................................................................................................................................................... the titration method gave 0ppm when the other three methods showed hydrogen sulfide was present. 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. A vapor liquid equilibrium is achieved which depends on the temperature. In 2008 approximately 10. 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 . At the ASTM D02 meeting at Tampa in December 2013. In addition to being toxic. As such. compared to 400. 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. 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. However. which was supported by the modified ASTM D7621/IP 570 method.Stanhope Seta Ian Mylrea Page 4 of 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. Earlier work in 2011 funded by the CCQTA4 showed that measurement of the hydrogen sulfide concentration in crude oil was difficult. 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.000 cars were transported by rail. of the four methods two methods results did make basic sense when compared. 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). 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). Colorado and North Dakota has lead to a surge in demand for transportation by railcar as pipeline access was unavailable. The report concluded that results between methods did not agree. On May 5th. how full the vapor space is and what other volatile components of the crude oil sample are present. The recent increase in production of volatile crude oil in Wyoming. The scavenger dosage required is a function of how much hydrogen sulfide is present in the liquid phase. Background Hydrogen Sulfide can occur naturally in crude3. 2013 a tank in Berthold. 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. and a boiling point of -60oC. GC and titration gave 10’s of ppm in liquid whilst the vapor method showed almost no hydrogen sulfide was present. 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. It is worth noting that not all the hydrogen sulfide can transfer to the vapor phase at once. Some scavengers work by reacting with hydrogen sulfide to form other less harmful compounds. Hydrogen sulfide can be removed by treatment with scavengers. hydrogen sulfide is highly reactive and is responsible for corrosion of infrastructure such as pipelines and rail cars.000 in 20131. 00 268. known as Procedure A (Vapor Phase Process). The test method precision enabled specification writers to include it in ISO 8217.Stanhope Seta Ian Mylrea Page 5 of 15 ASTM D7621/ IP 570.00 206 0. which enabled the vapor phase process to be developed and in 2012 IP 570 was standardised with a new procedure. in 2010. .0 0. low hydrogen sulfide in vapor predicted by D5705 gave relatively low liquid phase hydrogen sulfide by modified ASTM D7621/ IP570.03 Hydrogen Sulfide in Crude Oil - ASTM D7621 modified measurement of vapor phase versus liquid phase 250.0 50. Extensive research followed. 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.05 10. A study into potential interferences revealed that mercaptans and sulphides could elevate the readings.0 150. 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.00 >2000 2. with a maximum limit of 2.0 0. ASTM D7621 which is jointed with IP 570 had similar updates and is currently technically equivalent.0 200. the marine fuel specification.” Figure 1 Data provided by the Canadian Crude Quality Technical Association (CCQTA) Result (ASTM D5705) >2000 0. A separate hydrogen sulfide in distillate grade marine fuels study was carried out in 2011 which was added to the test method scope.00 mg/kg (liquid phase).5 0.0 0 500 1000 1500 2000 2500 ASTM D5705 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 2009.75 Sample 1 2 3 4 5 6 Result (ASTM D7621/IP 570) 117 0.0 100. similar to chromatography column techniques. 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. three successful round robin (ILS) studies. Inspection of the graph produced not only shows the magnitude but also the time which the peak occurred. it was . and is discussed later on. Test results obtained from a proficiency testing scheme which uses the standard show very close agreement between reference values and consensus values. all with good precision and extensive research into interferences. giving enormous confidence that the measurement is really hydrogen sulfide. which enabled the accuracy and precision to be confirmed. This places the detectors peak signal for hydrogen sulfide in a specific time frame. coupled with the earlier positive signs in the CCQTA programme and industry need with the development of an increase in production in the USA. Following recent experiences.Stanhope Seta Ian Mylrea Page 6 of 15 The method uses a hydrogen sulfide specific detector in conjunction with a cold vapor phase process to separate hydrogen sulfide from potential interferences. A standard was tested during the tests of which this paper is the subject. 1mL were employed in order to extend the range of the detector. Another test on the H2S Analyser was carried out back to back with the first from the 4 oz bottle. Figure 5 ASTM D5705 Apparatus and a crude oil sample During the 30 minutes one test was carried out on the H2S Analyser using the 4 oz bottle following ASTM D7621/ IP 570. ASTM D5705 measurements were carried out with the sample at 25oC (rather than 60oC) due to the volatile nature of the samples. Attention to replacing the cap promptly after each test was given.05 or 0. A 4 oz (125mL) glass bottle was also filled to the top (95%+). Small sample sizes such as 0. supplied over 95% full was gently turned end over end.Stanhope Seta Ian Mylrea Page 7 of 15 decided to develop an appendix in the hydrogen sulfide test method to enable wider use for measuring hydrogen sulfide in crude oil. Test Protocol Measurements by ASTM D7621/ IP 570 and ASTM D5705 were carried out within approximately 30 minutes of each other. The 1 litre bottle was placed in a 25oC water bath for 30 minutes. Colorimetric gas detector tubes in the range from 1000 to 10000 ppm (up to 1%) were used. In addition the 5 minute equilibrium time no longer applied. Effectively one test was done before and one after the ASTM . Figure 4 The test chamber for ASTM D7621/IP 570 ASTM D7621/IP 570 measurements were made with the sample at room temperature. Approximately 500ml was placed in a 1 litre glass bottle and the screw cap applied. 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. A 1 litre sample of crude oil from North Dakota. After 30 minutes the modified ASTM D5705 procedure was used to determine the vapor space hydrogen sulfide concentration of the 1 litre bottle. 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.Stanhope Seta Ian Mylrea Page 8 of 15 D5705 test. measure. Once the results were available the sample was recombined into the original 1 litre bottle and shaken to lower the hydrogen sulfide concentration. placed in a water bath and tested. This procedure (split. Occasionally a 3rd test was done using the modified ASTM D7621/IP 570 to gather additional data. . 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. combine. Stanhope Seta Ian Mylrea Page 9 of 15 Results The ASTM D7621/ IP 570 apparatus was verified as per the test method.97 120 100 80 60 40 20 0 0 2000 4000 6000 D5705 Modified 8000 10000 . Tests were conducted to demonstrate repeatability for D7621 and also comparison with vapor phase numbers.5 81 4.4 39 0. It was not always possible to do a D5705 test due to the volume of sample available. D5705 Modified Vapor Phase H2S (mg/kg) 9000 7000 6000 2500 2500 0 ASTM D7621/IP 570 Appendix Standard Liquid Phase H2S Deviation (mg/kg) (mg/kg) 146 6. Tests were then carried out to determine whether the typical sample injection volumes were practical. More detailed results can be found in Appendix 1.vapor measurement versus liquid phase measurement D7621 Crude Oil Appendix 140 y = 0.4 50 2.1 0 n/a Hydrogen Sulfide in Crude Oil .015x R² = 0.4 98 9. The average repeatability for ASTM D7621 was 9% (See Appendix 1). The best way to achieve this was to place the pipette in a beaker as shown. the container proportions (headspace versus liquid space) and temperature used. and away from draughts with the doors closed as far as was practical. The vapor liquid equilibrium is approximately 66. During the main study sample weights from 0. equating to 50 and 100 µL respectively. 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. 3. 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. Due to the low sample volumes. that is Liquid Phase H2S = 0.015 x Vapor Phase H2S. and is only applicable as a relationship for this particular crude oil. getting an accurate weight for the sample was critical. .Stanhope Seta Ian Mylrea Page 10 of 15 Results Discussion The main comparison shows that the vapor and liquid results correlate well with R2 = 0. mounted on a granite block. 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. 2.04 and 0. This was achieved in practice making sure the balance was a 4 place balance.97. 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 crude oil sample settled over time.08g were achieved with good repeatability. This is typical when compared to previous estimates in the literature3. During the initial tests with ASTM D7621/ IP 570 it was observed that the following were important… 1. vibration free. 7. 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. headspace and time allowed for the equilibrium to form (3 minutes). The following table describes the most appropriate volume of charge for the ASTM D7621/ IP 570 Crude Oil Appendix Hydrogen Sulfide (mg/kg) 0 to 10 mg/kg 10 to 20 mg/kg 20 to 100 100 to 200 above 200 Sample volume 5mL 1 or 2mL 0.1mL 0.Stanhope Seta Ian Mylrea Page 11 of 15 4.05mL 0. The diluent oil used became very full of air during the 5 minutes equilibrium time mentioned in ASTM D7621/IP 570 (11. Effectively the value obtained by this method will be a function of temperature (controlled at 60 oC normally or 25 oC for these tests).3). . The equilibrium time was not required as the test chamber was at ambient and therefore this step was omitted during the testing.025mL type of device Syringe Syringe Positive Displacement Pipette Positive Displacement Pipette Positive Displacement Pipette5 5. Other observations were as follows… 6. 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). Not all hydrogen sulfide is purged during the D5705 tests. Good stability of the samples over time was observed. 3 41.00 mg/kg had either a natural scavenger or applied scavenger and reacted with the hydrogen sulfide on blending.6 82.076 0.4 39.041 0.4 6.076 0. The certified value was 3.e.6 81.038 0.079 0.2 15.8 77.041 0.7 18.6 55.8 39. Unfortunately all the hydrogen sulfide had been removed.038 0. Tests B final test (0.2 17.074 0. It is quite likely that the sample containing 0.04 0.037 0. It was not possible to carry out a D5705 as the sample was too small. No D5705.079 0.21 mg/kg measured on the day.08 0.038 0.3 75.2 10.1 7. Test L was carried out to show the accuracy of the analyser when measuring a hydrogen sulfide standard.2 3. A D5705 test was not carried out.078 0. Tests I were by a different operator.3 11.071 0.8 58.041 0.5 8. Test E was the measurement of the subsequent blend. Tests F and G were on previously bottled samples which were approximately 60% full.6 48.9 52.00 mg/kg) was an experiment to demonstrate that all the hydrogen sulfide is measured during D7621.9 54.2 0 83. Again no D5705.8 92.6 46.074 0.4 51.6 63.037 0.081 0.00 mg/kg sample (to try to make 20 mg/kg).8 0.04 mg/kg which compares very well to the 3.082 1. Tests D were carried out on the 1 litre sample container prior to blending with a 0. B. in parallel by both methods.7 1.079 4.7 1.037 0.08 0. 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.Stanhope Seta Ian Mylrea Page 12 of 15 Appendix 1 Notes Tests A. The tests are useful to show potential repeatability. Tests H was on one of the same bottles as G and H after shaking to lower the levels.644 50 50 50 50 50 50 50 50 50 50 100 100 2000 100 100 100 100 100 100 100 100 100 100 100 100 5000 9000 7000 6000 0 2500 2500 2500 2500 n/a .625 0.2 0 74.078 0. C. Test ASTM D7621 (Crude Oil Appendix) Repeat (mg/kg) A A B B B B C C D D D D E F F G G H H I I J J K K L 141 150 109 92. however the results are useful to estimate repeatability.8% Sample Mass Sample Volume ASTM D5705 modified (g) (µL) (ppmv) 0.21 repeatability max % 1 2 1 2 3 n/a 1 2 1 2 3 4 n/a 1 2 1 2 1 2 1 2 1 2 1 2 1 Average repeatability 6. J and K were conducted following the test protocol i.3 46. Stanhope Seta Ian Mylrea Page 13 of 15 ASTM D7621/ IP 570 Crude Oil Appendix Proposal APPENDIX (Nonmandatory Information) X1. X1.2.2. NOTE 1— If it is suspected that the sample contains a large amount of volatile components such as butane then use 0.1 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.1 Prepare the apparatus as per Section 9 & 10 ASTM D7621/IP 570. During sample injection avoid drawing sample vapors into the pipette before removing the pipette from the test chamber.2 Follow the steps in Section 11 for Procedure A with the following additions. NOTE 3—This procedure is critically dependent on the weighing of the sample and injection of the sample into the sample test chamber.2).3. X1. 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. so that the test vessel is at room temperature. X1.2. Alternative procedure for the measurement of hydrogen sulfide in crude oil at room temperature X1.3. In this procedure the test vessel is located in a support bracket at room temperature.4 The appropriate volume shall be determined by reference to Table X1.1 Place the support bracket in the temperature controlled test vessel heating jacket.3.3 Carefully invert the sample end over end two times to mix the sample.1 Support bracket X1.2.3. . NOTE 2—A single mass can be entered rather than entering the mass before and after sample introduction if the balance is tared. X1.3.2 Apparatus X1.3.2 Insert the test vessel in the support bracket and fit the input/output tubing. X1.2.1ml sample size to prevent pressurization of the test vessel.3 Procedure X1. X1. 025mL Page 14 of 15 Sample Introduction Disposable syringe Disposable syringe Pipette Pipette Pipette TABLE X1 Appropriate Test Volume for Expected H2S Concentration X1.05mL 0.Stanhope Seta Ian Mylrea Expected H2S Concentration 0 to 10 mg/kg 10 to 20 mg/kg 20 to 100 mg/kg 100 to 200 mg/kg Above 200 mg/kg Required Test Volume 5 mL 2 mL 0.4 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%. .1 mL 0. Analysis and Evaluation. by Jeanine Prezioso 3 Crude Oils Their Sampling. January 25 . March 2012 5 The Gilson Microman positive displacement pipette was used during the study and found to be suitable . May 15 2013: Enbridge may shut Bakken oil rail terminal in sulfide gas dispute. 2014: Accidents surge as oil industry takes the train.Stanhope Seta Ian Mylrea Page 15 of 15 References 1 th New York Times. Harry N Giles & Clifford O. by Clifford Krauss and Jad Mauawad 2 th Reuters News Agency. Mills 4 Canadian Crude Quality Technical Association Hydrogen Sulfide in Crude Measurement Report – Bill Lywood & Dave Murray.