Copyright © the author(s). This work is licensed under a Creative Commons Attribution 4.0 International License. Improved Oil and Gas Recovery DOI: 10.14800/IOGR.1355 Received January 2, 2025; revised March 27, 2025; accepted May 27, 2025. *Corresponding author: dike.chukwuebuka@futo.edu.ng 1 Study On Hydrate Formation Potential in Natural Gas Pipeline Anthony Ogbaegbe Chikwe, Chukwudozie Ian Awah, and Chukwuebuka Francis Dike*, Federal University of Technology Owerri, Owerri, Nigeria Abstract The formation of hydrates within the natural gas pipeline poses a significant challenge that requires careful attention and management. This research endeavor is focused on predicting and forecasting the specific conditions under which hydrate formation is likely to occur within the natural gas pipeline infrastructure. By understanding these conditions, it becomes possible to implement preventive measures and strategies to mitigate the risks associated with hydrate formation. The work aims to ascertain the precise temperatures and pressures at which hydrocarbon and water dew points are reached within gas streams. Determining these dew points is crucial because it allows for the optimization of pipeline operations, ensuring that the gas remains in a stable state and does not precipitate into hydrates or condense into liquid form, which could lead to blockages and operational inefficiencies. The study examined the formation of hydrates and the deposition of hydrocarbon slugs, which are primary concerns in gas pipelines that can lead to significant environmental damage and substantial financial repercussions. The prediction of hydrate formation conditions and the pipeline segments where these conditions are likely to occur was conducted to provide a basis for designing a cost-effective hydrate prevention strategy. Additionally, the prediction of the hydrocarbon and water dew points of a gas stream was accomplished using two equations of state within the Aspen HYSYS simulation software. This analysis confirms that under specific conditions of elevated pressure and reduced temperature, hydrate formation is promoted or favored, and water condenses out prior to hydrocarbons in natural gas streams. This paper serves as a guide for forecasting the conditions conducive to gas hydrate and hydrocarbon liquid formation, as well as identifying pipeline sections prone to hydrate formation in long-distance pipelines. In essence, this research seeks to enhance the safety, reliability, and efficiency of natural gas transportation by providing a comprehensive understanding of the thermodynamic conditions that govern the behavior of gas streams within pipelines. Introduction Fossil fuels recorded major contributions to global energy consumption with an estimated 87 million barrels/day (BPD) and this has raised the stakes for oil production despite obvious productivity decline (Kerunwa et al. 2024). Fossil Fuels could be solid (coal and/or tar sand), liquid (crude oil) or gaseous (natural gas) in nature (Meyers 2002), but gaseous based fossil fuel has recorded significant global attention from several countries (Ikoku 1992) due to its excellent eco-properties compared to other fossil fuel forms (Mohammad 2009). Natural Gas is a gas derived conventional underground formation either as gas associated with crude oil or free water (Anyadiegwu et al. 2014), and comprises predominantly of methane, significant quantities of ethane, propane, butane and pentane (Abdel et al. 2003), and other impurities such as water vapour, carbon (iv) oxide and hydrogen sulphide. The study of hydrates (also known as “gas hydrates”) has captured the attention of the industry and the economy because of the identification of its vast deposits (as new energy source), concurrent lack of traditional fossil fuels (Guimin et al. 2022) and its adverse effects in pipelines and process equipment. Gas hydrates are structured crystalline materials with an organized structure in which methane and other guest molecules are enclosed in cages made of water molecules and held in place by hydrogen bonds. Since an empty cage lacks thermodynamic stability, these guest molecules are essential for stabilizing the cages (Naser and Brandstatter 2011). Hydrates fobendsh pressures and low temperatures, in the presence of free water especially near regions with significant agitation and turbulence like valves mailto:modibbo.edu@gmail.com Improved Oil and Gas Recovery 2 and bends and can impede pipelines in deep sea or permafrost conditions. Due to this clogging, dangerous working conditions, high operational costs, and even the possibility of fatal accidents are all created. Predicting the critical sections of the natural gas pipeline at which hydrates form is very crucial for pipeline operation optimization and for a better pipeline cost optimized hydrate prevention methods. However, since it is not feasible, to empirically determine segmental variations in pressure, temperature, density, viscosity, etc., along a transmission pipeline, these parameters are determined by applying thermodynamic and conservation principles (Carroll 2003). Also, precise measurement of hydrocarbon dew points is vital in achieving safe and efficient transportation through natural gas pipelines specific for single phase fluids (Shoaib et al. 2018). The conditions (pressure and temperature) at which the heavier elements condense out of the gas stream and turn into liquids are known as the hydrocarbon dew point (HCDP). In some regions, ambient temperatures regularly cause natural gas streams to cool to their hydrocarbon dew points, resulting in condensation taking place in transmission pipelines. If these condensed liquids are not recovered, the stream will lose the heating value they represent, and the liquids themselves could cause equipment in the natural gas delivery system to malfunction, (George et al. 2005). From an analytical gas composition, various techniques can be used to predict hydrocarbon dew point using chilled mirror apparatus, various software programs and equations of state. Industry experience, however, suggested that these various approaches would yield noticeably different outcomes, particularly when the proportions of heavier and hexane (C6)-containing substances are significant (Galatro and Marin-Cordero 2014). Methodology Hydrate Formation Prediction. HYSYS simulation package was used to simulate the thermodynamic environment that will suit transportation of the natural gas stream through a gas pipeline. With the Peng Robinson’s equation of state (PR EOS) as the fluid package, the temperature and pressure variations at varying sections of the pipeline were determined. For each pipeline section, HYSYS calculates the Hydrate formation temperature at the prevalent section’s pressure, for which a careful comparison with the section’s prevalent temperature determines the pipeline section’s susceptibility to hydrate formation. Hammerschmidt correlation for hydrate formation temperatures used to validate the formation temperatures obtained at each pipe section’s pressure. 𝑇 = 8.9𝑃0.285 ,..................................................................................................................................................................(1) where T is the hydrate formation temperature, Fahrenheit; and P is the pressure, psi. Table 1 displays the detailed composition of the natural gas that is utilized for the purpose of predicting the formation of gas hydrates. The primary constituent found within this natural gas is methane, which plays a crucial role in the overall analysis and understanding of hydrate behavior. Table 1—Composition of the natural gas for hydrate prediction. Mole Fraction Methane 0.7120 Ethane 0.1040 Propane 0.0644 i-Butane 0.0090 n-Butane 0.0196 i-Pentane 0.0051 n-Pentane 0.0056 n-Hexane 0.0024 n-Octane 0.0001 H2S 0.0200 Nitrogen 0.0190 CO2 0.0380 n-Heptane 0.0008 Improved Oil and Gas Recovery 3 Dew Point Prediction. Two equations of states, namely the Peng-Robinson and the Soave-Redlich-Kwong are used as the fluid packages in HYSYS to predict the hydrocarbon and water dew points of a natural gas stream at designated pressure points and produce a phase envelope for the gas stream. Table 2 presents the gas composition utilized for the prediction of the dew point. A careful comparison analysis between the hydrocarbon and water dew point with each equation of state confirms the behavior of gas streams, where the heavier components condense out first. Table 2—Gas Composition for dew point prediction. Mole Fractions Nitrogen 0.0569 CO2 0.0020 Methane 0.8274 Ethane 0.0790 Propane 0.0214 i-Butane 0.0034 n-Butane 0.0053 i-Pentane 0.0012 n-Pentane 0.0014 n-Hexane 0.0012 n-Heptane 0.0005 n-Octane 0.0001 n-Nonane 0.0000 n-Decane 0.0000 n-C11 0.0000 n-C12 0.0000 H2O 0.0001 Results and Discussion To ascertain which sections of the pipeline are most vulnerable to the formation of hydrates, a meticulous comparison was conducted between the prevailing temperatures of each section of the pipeline and the corresponding temperatures at which hydrates are known to form. This process involved a detailed analysis to identify any potential discrepancies or areas where the pipeline's temperature might drop below the threshold required for hydrate formation. Furthermore, to ensure the accuracy and reliability of the determined hydrate formation temperatures, a validation process was undertaken using the well-established Hammerschmidt correlation. This correlation, which is widely recognized in the industry, provides a means to predict hydrate formation temperatures based on the specific conditions within the pipeline. The results of this validation process, which confirmed the accuracy of the calculated hydrate formation temperatures, are presented and illustrated in Appendix A1. This table serves as a crucial reference, offering a comprehensive overview of how the calculated temperatures align with the established Hammerschmidt correlation, thereby providing a robust foundation for further analysis and decision-making regarding the management and mitigation of hydrate formation risks within the pipeline system. It indicates that within section 10 of the pipeline and in areas below, the temperature at which hydrates form exceeds the prevailing temperature of the pipeline, rendering these sections prone to hydrate formation. Figure 1 shows that pressure and temperature slowly decline as we move down the pipeline section. It is worthy to note that the pressure decline with increasing pipe length is uniform, while a steep temperature decline is observed at the beginning of the pipeline and a more gradual decline with increasing length of the pipeline. Figure 2 shows the relationship between the pipeline pressure, pipeline temperature, HYSYS Hydrate formation temperature and the Hammerschmidt Hydrate formation temperature. The region below the pipeline temperature and the HYSYS Hydrate formation temperature depicts the hydrate formation region. An acceptable difference of 4.35% exists between the Hammerschmidt and HYSYS HFT due to the presence of Hydrogen Sulphide in the gas stream, as Hammerschimdt correlation was developed mainly for sweet gases. Improved Oil and Gas Recovery 4 Figure 1—Pressure and temperature change against pipeline length. Figure 2—Pipeline temperature, HYSYS HFT and Hammerschmidt HFT. Appendix A2 presents the outcomes of the simulated water and hydrocarbon dew points employing the Peng-Robinson and Soave-Redlich-Kwong equations of state. A meticulous examination reveals an average disparity of approximately 0.8% and 0.12% for the hydrocarbon and water dew points, respectively, between the dew point temperatures simulated by the Peng-Robinson and those by the Soave-Redlich-Kwong at each specified pressure point. This discrepancy is attributed to the greater complexity of the Peng-Robinson equation of state, which accounts for molecular shape and the presence of associating molecules—those capable of forming weak associations, such as hydrogen bonds—whereas the Soave-Redlich- Kwong equation does not. Regardless of the type of equilibrium oil saturation (EOS) that is employed in the analysis, a comparison between the water dew points as depicted in Figure 3 and the hydrocarbon dew point as shown in Figure 4 reveals a significant observation. Specifically, it becomes evident that the temperature at which the water dew point is reached occurs earlier than the temperature at which the hydrocarbon dew point is attained under certain pressure conditions. This sequence of condensation events can be explained by the inherent properties of the components involved. In this scenario, water, being the heavier component, tends to condense out of the gas stream prior to the hydrocarbon, which is lighter in molecular weight. This behavior is consistent with the general principle that in a gas mixture, the component with a higher molecular weight and a greater affinity for condensation will precipitate out of the gas phase before the lighter components do. Improved Oil and Gas Recovery 5 Figure 3—Comparison between the PR and SRK water dew points. Figure 4—Comparison between the PR and SRK hydrocarbon dew points. In Figure 5, a detailed comparison has been conducted to illustrate the differences between the hydrocarbon dew point and the water dew point, utilizing the PR EOS as the analytical framework. This comparison reveals a consistent trend where, across a range of different pressures, the hydrocarbon dew point invariably exceeds the water dew point. Figure 5—Comparison between hydrocarbon dew point and water dew point using PR EOS. Improved Oil and Gas Recovery 6 Conclusion Long-distance pipelines can use the study done on the sample gas pipeline above as a reference for forecasting gas-hydrate formation conditions and anticipated hydrate formation locations. It also provides an insight into designing and cost- optimizing hydrate prevention schemes, like stating the pipeline section to insulate or to inject inhibitors. For this specific pipeline, the remediation methods should be implemented at the beginning sections of the pipeline, as the hydrate formation conditions are most likely to be met at these points. Furthermore, HYSYS can be used to determine the temperature and pressure at which liquid hydrocarbon and water will condense out of the gas stream with reasonable accuracy especially with the Peng-Robinson’s and Soave-Redlich-Kwong’s equation of state. Conflicting Interests The author(s) declare that they have no conflicting interests. References Abdel, A.H.K., Mohamed, E. and Fahim, M.A. 2003. Petroleum and Gas Field Processing. New York: Marcel Dekker Inc. Anyadiegwu, C.I.C., Kerunwa, A. and Oviawele, P. 2014. Natural Gas Dehydration using Triethylene Glycol (TEG). Petroleum and Coal 56(4): 407-417. Caroll, J., 2003. Natural Gas Hydrates a Guide for Engineers. Elsevier. Galatro, D., and Marín-Cordero, F. 2014. Considerations for the Dew Point Calculation in Rich Natural gas. Journal of Natural Gas Science and Engineering 18: 112-119. George, D. L., Barajas, A. M., and Burkey, R. C. 2005. The Need for Accurate Hydrocarbon Dew Point Determination. Pipeline & gas journal 232(9), 32-34. Guimin, Y., Hao, J., and Qingwen, K. 2022. Study on Hydrate Risk in The Water Drainage Pipeline for Offshore Natural Gas Hydrate Pilot Production. Frontiers in Earth Science 9(1):1-12. Ikoku, C. I. 1992. Natural Gas Production Engineering. Boca Raton, USA: Krieger Publishing Company. Kerunwa, A., Izuwa, N.C., Dike, C.F., et al. 2024. Review on the Utilization of Local ASP in the Niger-Delta for Enhanced Oil Recovery. Petroleum and Coal 66(1): 256-275. Meyers, R.A. 2002. Encyclopedia of Physical Science and Technology. Academic Press. Naseer, M. and Brandstätter, W. 2011. Hydrate Formation in Natural Gas Pipelines. WIT Transactions on Engineering Sciences 70: 261–269. Shoaib, A.M., Bhran, A.A., Awad, M.E., et al. 2018. Optimum Operating Conditions for Improving Natural Gas Dew Point and Condensate Throughput. Journal of Natural Gas Science and Engineering 49(1): 324-330. Anthony Ogbaegbe Chikwe is a Senior Lecturer at the Department of Petroleum, Federal University of Technology with research interest in Production, and Reservoir & Gas Engineering. He holds bachelor’s degree and master’s degree in Petrochemical Engineering from University of Oil and Gas, Moscow, Russia, and PhD degree in Petroleum Engineering from Federal University of Technology Owerri, Owerri, Nigeria. Chukwudozie Ian Awah is a graduate candidate at the Department of Petroleum Engineering, Federal University of Technology Owerri, with research interest in natural gas engineering. Chukwuebuka Francis Dike is a Research Technologist at the Department of Petroleum Engineering, Federal University of Technology Owerri, Owerri, Nigeria. He has research interest in drilling, drilling fluids technology, reservoir engineering, enhanced oil recovery and flow assurance. Dike Holds a bachelor’s degree and master’s degree in petroleum engineering. Improved Oil and Gas Recovery 7 Appendix Appendix A1—Pipeline temperature and pressure variations with hydrate formation temperature. Pipe Sections Axial Length (ft) Pressure (psi) Temperature (F) HYSYS HFT (F) Hammerschmidt HFT (F) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 0.000 546.810 1640.420 2734.030 3827.650 4921.260 6014.870 7108.490 8202.100 9295.710 10389.330 11482.940 12576.550 13670.170 14763.780 15857.390 16951.010 18044.620 19138.230 20231.850 21325.460 22419.070 23512.690 24606.300 25699.910 26793.530 27887.140 28980.750 30074.370 31167.980 32261.590 32808.400 2139.310 2137.900 2135.120 2132.390 2129.700 2127.050 2124.420 2121.810 2119.220 2116.640 2114.070 2111.520 2108.960 2106.420 2103.870 2101.330 2098.790 2096.250 2093.710 2091.170 2088.630 2086.090 2083.550 2081.000 2078.450 2075.900 2073.350 2070.790 2068.230 2065.670 2063.110 2061.820 140.000 132.850 119.820 109.090 100.250 92.970 86.980 82.040 77.970 74.630 71.870 69.600 67.730 66.190 64.920 63.870 63.010 62.310 61.720 61.240 60.850 60.520 60.250 60.030 59.850 59.700 59.580 59.470 59.390 59.320 59.260 59.240 75.419 75.416 75.409 75.401 75.394 75.387 75.380 75.373 75.366 75.360 75.353 75.346 75.339 75.333 75.326 75.319 75.312 75.306 75.299 75.292 75.285 75.279 75.272 75.265 75.258 75.252 75.245 75.238 75.231 75.223 75.218 75.214 79.162 79.147 79.118 79.089 79.061 79.033 79.005 78.977 78.950 78.922 78.895 78.868 78.841 78.813 78.786 78.759 78.732 78.705 78.678 78.650 78.623 78.596 78.569 78.541 78.514 78.486 78.459 78.431 78.404 78.376 78.348 78.334 Improved Oil and Gas Recovery 8 Appendix A2—Hydrocarbon and water dew point temperatures using the PR and SRK EOS. Pressure (bar) WDP (K)-SRK WDP (K)-PR HCDP (K)-SRK HCDP (K)-PR 2.20 2.60 3.90 4.70 5.90 7.30 8.00 9.70 10.60 11.20 12.90 14.10 15.60 16.50 17.70 18.90 20.40 21.30 22.30 23.40 24.80 26.00 27.20 28.50 29.70 31.40 33.30 35.20 36.80 38.70 41.10 42.40 44.00 45.40 46.80 48.50 50.90 53.90 56.90 59.50 61.60 235.14 236.74 240.71 242.58 244.88 247.06 248.00 250.00 250.93 251.50 252.98 253.91 254.97 255.55 256.28 256.97 257.76 258.21 258.68 259.18 259.77 260.25 260.71 261.18 261.60 262.15 262.73 263.27 263.70 264.18 264.74 265.03 265.37 265.66 265.93 266.25 266.67 267.15 267.60 267.96 268.23 234.85 236.46 240.44 242.31 244.61 246.80 247.74 247.75 250.67 251.25 252.73 253.66 254.71 255.30 256.03 256.71 257.51 257.95 258.43 258.92 259.52 260.00 260.45 260.92 261.33 261.89 262.46 263.00 263.43 263.91 264.47 264.76 265.10 265.38 265.65 265.70 266.39 266.87 267.31 267.67 267.94 258.30 260.07 264.94 267.10 269.95 272.30 273.48 275.84 276.58 277.17 278.79 279.97 281.00 281.43 282.03 282.47 283.21 283.60 284.09 284.53 284.98 285.12 285.27 285.42 285.57 285.86 286.10 286.30 286.45 286.60 286.30 286.15 286.00 285.90 285.71 285.57 285.36 284.98 284.09 283.35 282.32 256.13 257.86 262.83 265.05 267.89 270.24 271.42 273.78 274.64 275.10 276.87 277.90 278.90 279.23 279.82 280.40 281.00 281.86 281.88 282.30 282.52 282.85 283.00 283.20 283.35 283.50 283.65 284.00 284.02 283.94 283.70 283.60 283.50 283.35 283.21 282.76 282.32 281.80 281.00 280.11 279.37