International Journal of Engineering Sciences, 2(8) August 2013, Pages: 327-331

TI Journals

International Journal of Engineering Sciences www.tijournals.com

ISSN 2306-6474

* Corresponding author. Email address: kaykaysalam@yahoo.co.uk

Prediction of Hydrate Formation Conditions in Gas Pipelines

Salam K. K. *1, Arinkoola A. O. 2, Araromi, D. O. 3, Ayansola Y. E. 4 1,2,3,4 Petroleum Engineering Unit, Department of Chemical Engineering, Ladoke Akintola University of Technology(LAUTECH), P.M.B. 4000, Ogbomoso, Nigeria.

A R T I C L E I N F O A B S T R A C T

Keywords: HYSYS Hydrate Modelling

Transportation of gas from one place to another has been encountering quite a number of problems over a period of time, and one of them is the formation of gas hydrates in gas pipelines. The petroleum and gas industry spends hundreds of millions of dollars annually combating their effects. In order to avoid costly losses due to the formation of these hydrates, several methods which include thermodynamic modeling and empirical correlations have been used in predicting the conditions for hydrate formation. This work predicts the hydrate formation condition for three different gas streams using HYSYS simulation package. The predicted conditions were compared with published used empirical methods [1] and there is a close agreement between the predicted result from HYSYS and the result calculated using published empirical methods.

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1. Introduction

Methane hydrate are clathrate structures that traps methane molecules in a solid ice-like phase, and are formed under conditions favorable on sea bottoms, in gas pipeline, as well as under permafrost areas [2]. Examples of gases that are likely to combine with water molecules to form hydrates include light alkanes such as methane and iso-butane. Other gases include carbondioxides, hydrogen sulphide, nitrogen, oxygen and argon[3]. Depending on the size of the quest molecules, natural gas hydrate can consist of any combination of three crystal structures: Structure I which allows the inclusion of both methane and ethane but not propane in its composition; Strucrure II which allows inclusion of propane and isobuthane in addition to methane and ethane and Structure H which accommodate higher quest molecules such as Iso-pentane [4]. Sloan (1991) described Hydrate as a nuisance because they block transmission lines, plug blow out preventors, jeopardize the foundations of deep water platforms and pipelines causing tubing and casing collapse and foul heat exchangers valves and expander [5]. Preventive measures are Pipe depressurerization of deep water pipe line to remove plugs frequently requires days of flow interruption, unusual drilling mud compositions which are expensive and cause environmental concern and Injecting inhibitor to flow line which are insoluble insolubility in free water that leads to loss of inhibitor to gas face or HC liquid face [6]. 5- 8% of total plant cost is required to prevent hydrate formation. All the problems encountered can be avoided by operating outside the hydrate region or transporting hydrate as slurry, the economics of the first option to largely dependent on the accurate determination of the hydrate phase boundary whereas the amount of hydrate to be transferred could be the main factor in the success of the second option [7]. Mcleod (1978) analyzed and compared four widely used method of predicting the water content of natural gas hydrate. He considered conditions for gas hydrate formation, methods of preventing hydrate formation and inhibitor choices. There are methods to calculate the equilibrium conditions of hydrate formation or predicts condition under which hydrate formation is likely to occur in any of several pure or multicomponent hydrocarbon gas systems [8]. Russo and Gasparetto (1991) developed a computational algorithm to predict conditions of hydrate formation in natural gas system which includes the effect of inhibitors. They made use of Peng-Robinson EOS adopting vander Waals and plateuw’s model to develop a relationship between fraction of crystal lattice occupation by gas mixture, system pressure and temperature which led to sketching of curves indicating region of viable hydrate formation. The strength of the model is its applicability under different inhibitors [9]. There was a lot of improvement on the adoption of Vander Waals and Platteuw’s for basis for hydrate conditions prediction in pipeline, one of them is the work of Zhu et al (2005)[2] who developed a thermodynamic software module for hydrate formation conditions for CH4, CO2 and CH4-CO2 mixed hydrate. This model can predict thermodynamic behavior of gas hydrate i.e. pressure and temperature at which hydrate will form and also hydrate equilibrium conditions in presence of salt. The results from the model are in close agreement with the experimental data reported in the literature.

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Bhangole et al (2006) extended Vander Waals and Platteuw’s to predictions of hydrate formation in the reservoir. They developed a pore-freezing model that can be used to predict gas hydrate equilibrium for pure CH4,CO2 and mixed CH4 –CO2 system in saline pore water for any pure size distribution. They used EOS developed for bulk gas hydrate equilibrium conditions based on vander Waals –platteuw’s model. The model is implements with FORTRAN code and the model is capable of calculating equilibrium gas hydrate saturation at any given pressure, temperature and initial salt concentration and also to calculate hydrate equilibrium condition for salt in a mixed CH4-CO2 gas hydrate system [9]. Another model applied in offshore and deep water environment is the work of Mohammadi &Tohidi(2006)[7]. They developed a model to predict the hydrate free zone in mixed salt and chemical inhibitors designed for offshore and deep water applications. It was based on combinations of the Valderrama modifications of the Patel-Teja containing of state with non-density dependent mixing rules and a modifications of a debye-Huckel electrostatic term, which is applied to system containing salt and chemical inhibitors by correcting the properties of the aqueous phase results are compressed with published data in the literature evaluated using hydration dissociation data. Prevention of formation of hydrate is of paramount important because this is defimately save 5-8% of total plant cost[5] and several methods has been adopted in prediction of hydrtate free zone when designing transportation of gas. Gas has different composition which makes their behavior and hydrate formation condition differes [10]. Hysys simul;ation package will adopted in prediction of hydrate formation conditions for a stream of sweet and sour gas in the presence of carbon dioxide. 2. Methodology

Table 1 show three different compositions of natural gas extracted from Gas Processors Suppliers Association (GPSA, 2004) [11]. HYSYS simulation package was be used to simulate the thermodynamic environment that will suit transportation of the gas stream which leads to determination of hydrate formation conditions (pressure and temperature). Hydate formation conditions were calculated using empirical methods adopted in Katz et al (1959)[1].

3. Results and Discussion

3.1 Prediction Of Hydrate Formation In Gas Pipeline Containing Natural Sweet Gas For a pipeline transporting a stream of sweet natural gas containing purely methane and other hydrocarbons, i.e. the stream contains 92.7% methane and the other compositions consist of ethane, propane, butane and pentane without other compounds. With the above composition, hydrate formation temperature is 12.1302oC, this implies that the gas stream must be maintained at a temperature above or at this value and the pressure should be maintained at 1539.71KPa or below it, else hydrate type I and II will be formed in the pipeline. This is shown in Figure 1.

3.2 Prediction of hydrate formation in pipeline transporting a gas stream containing sweet gas and CO2 For a gas stream containing 78% methane, 9% nitrogen, 0.2% carbondioxide with the remaining as other light hydrocarbons. The carbon dioxide content of the gas reduces the equilibrium formation temperature to 9.21oC from 12.13oC of the pure sweet gas. However, the gas cannot be flown at any pressure as for pure sweet gas but at a pressure lower than 2316.68KPa. Figure 2 show the predicted condition and any deviation in the values of the equilibrium pressure and temperature will cause type I and II hydrate to form in the pipe. 3.3 Prediction of hydrate formation in a pipeline transporting sour gas with traces of CO2

Sour gas is a gas stream containing hydrogen sulphide in it. For a gas stream containing 84.3% methane, 4.2% hydrogen sulphide, 0.2% nitrogen and 6% carbondioxide and other light hydrocarbons making up for the remaining composition, the equilibrium hydrate temperature is 15.861oC and the pressure is 4280KPa. This implies that the temperature of the stream must be maintained above the equilibrium temperature and the pressure should be less than 4280.72KPa. Violating these conditions will lead to hydrate type I and II forming. 3.4 Comparing the predicted results with the calculated results For each type of composition of gas stream, we have two results; the predicted result from HYSYS and the calculated results from Katz chart and Baille & Wichert method which are both presented in the GPSA handbook. The results on compared in the table 2 below:

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Figure 1. HYSYS presentation of hydrate prediction of a stream of sweet gas in a pipeline

Figure 2: HYSYS presentation of hydrate prediction of a stream of sweet gas and CO2

Figure 3: hysys presentation of hydrate prediction for a pipeline transporting a stream of sour gas and CO2

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Figure 4: comparison of predicted and calculated hydrate formation pressure

0500

10001500200025003000350040004500

sweet gas sweet gas+CO2 sour gas+CO2

calculated(KPa) predicted(KPa)

Figure 5: Comparison of hydrate formation temperature for different streams

02468

1012141618

Sweet gas Sweet gas + CO2 Sour gas + CO2

Calculated(degree celsius) Predicted(degree celsius)

Table1. Composition of different gas streams

Component Sweet gas Sweet gas+CO2 Sour gas+CO2

Methane 0.926700 0.784000 0.842531 Ethane 0.052900 0.060000 0.031494 Propane 0.013800 0.036000 0.006699 i-Butane 0.001800 0.005000 0.002000 n-Butane 0.003400 0.019000 0.001900 Pentane 0.001400 - 0.003999 Nitrogen - 0.094000 0.002999

Hydrogen sulphide - - 0.041792 Water - - -

Carbondioxide - 0.002000 0.066587 Source: GPSA (2004)[11]

Table 2. Comparison of predicted and Calculated Result.

Component Predicted result Calculated result Sweet gas 1539.713KP and 12.1302oC 1570KPa and 4oC Sweet gas+CO2 2316.683KPa and 9.2096oC 2100KPa and 10oC Sour gas+CO2 4280.7159KPaand 15.861oC 4200KPa and 16oC

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4. Conclusions

HYSYS simulation tool can be used for prediction of hydrate free zone judging from its prediction of hydrate formation conditions which were in acceptable agreement with the calculated result demonstrating the reliability of the simulation tool for sweet and sour gases in the presence of CO2. References [1] Katz D.L. et al 1959 “Handbook of Natural Gas Engineering”, McGraw-Hill Book Co., Inc [2] Zhu, T., Mc Grail, B. P., Kulkarni, A. S., White, M. D., Phale, H. and Ogbe, D. 2005 “Development of a thermodynamic model and reservoir

simulator for the CH4, CO2 and CH4-CO2 gas hydrate system”, SPE 93976 paper presented at the SPE Western Regional Meeting held in Irvine, CA,USA 3Oth March- 1st April 2005, pp 1-8.

[3] Carroll, J. J. 2004 “An examination of the prediction of hydrate formation conditions in sour natural gas”, GPA Europe, Spring Meeting Dublin, Ireland; May 19-21, pp 1-17.

[4] Abraham L.T.and Varma E.N. 2007 “ Extraction of Methane from Gas hydrate using Anaerobic Archaebacteria”, OTC 18551 paper presented at the 2007 Offshore Technology Conference held in Houston, Texas, 30 April – 3 May, 2007, pp.1-12

[5] Sloan, E.D. 1991 “ Natural gas hydrate”, SPE 23562, Journal of Petroleum Technology, 1-4. [6] Paez, J. E., Blok, R., Vaziri, H. and Islam, M. R. 2001 “Problems in Hydrates: Mechanisms and Elimination Methods”, SPE 67322 prepared for

presentation at the SPE Production Operations Symposium held in Oklahoma City, Oklahoma, 26-28 March 2001, pp. 1-9. [7] Mohammadi, A. H. and Tohidi, B. 2006 “Gas hydrate and deep water operation: predicting the hydrate free zone, Paper SPE 99427 presented at the

SPE Europe/EAGE Annual Conference and Exhibition held in Vienna, Austria, 12-15 June, 2006, pp. 1-4 [8] McLeod, W.R. (1978): Prediction and control of natural gas pipeline. SPE8137 presented at the European offshore petroleum conference and

exhibition in London 24-27 October, 1978, pp.1-8 [9] Rossi, L.F. and Gas paretto, C. A .1991 “Prediction of hydrate formation in natural gas system, paper SPE 22715 presented at the 66th Annual

Technical Conference exhibition of the SPE held in Dallas, TX ,October 6-9,1991.pp. 1-7. [10] Bhangole, A. Y. , Zhu, T., Mc Grail, B. P. and White, M. D. 2006 “A model to predict gas hydrate equilibrium and gas hydrate in the process

media including mixed CO2 –CH4 Hydrates”, paper SPE 99759 paper presented at the 2006 SPE/DOE symposium on improved oil recovery held in Tulsa, Oklahoma,22-26,April 2006, Pp. 1-7

[11] Gas Processors Suppliers Association 2004 “Engineering Data book, 12th Edition, section 20, pp. 1-15