LABORATORY EXPERIMENTS & MODELING FOR HYDRATE FOR- MATION AND DEPOSITION FROM WATER SATURATED GAS SYS- TEMS

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1 Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011), Edinburgh, Scotland, United Kingdom, July 17-21, LABORATORY EXPERIMENTS & MODELING FOR HYDRATE FOR- MATION AND DEPOSITION FROM WATER SATURATED GAS SYS- TEMS Ishan Rao, E. Dendy Sloan, Carolyn A. Koh, Amadeu K. Sum * Center for Hydrate Research, Department of Chemical Engineering Colorado School of Mines 1600 Illinois St., Golden, CO UNITED STATES OF AMERICA ABSTRACT One of the major issues in flow assurance includes plugging due to hydrate formation and deposition. A key uncertainty in gas pipelines is hydrate deposition on the pipe wall. This work demonstrates hydrate formation and deposition on a cold surface in water-saturated gas systems. Methane hydrate deposition can be achieved in a laboratory-scale apparatus by nucleation of hydrates from the gas phase on the outer surface of a cold tube. This indicates that wall hydrate deposition is possible in saturated systems. The deposit progresses from the initial nucleation to crystal growth to hardening (annealing) stages, growing from initially a porous to a relative nonporous deposit. This deposition of hydrates is analogous to frost deposition. The methane hydrate deposit thickness gradually decreases and reaches a limit as the surface reaches the hydrate equilibrium temperature. A deposition model, which has been used for frost, matches well with experimental volumetric deposition. The model shows an increase in hydrate thickness and a decrease in the distance for a plug formation length with an increase in saturation and a decrease in fluid velocity. The initial hydrate deposition model results are in good agreement with the experimental data, showing that a decrease in hydrate porosity decreases the surface temperature of the hydrate deposit. Keywords: Gas dominated pipelines, hydrate deposition, pressure drop, flow assurance NOMENCLATURE C p Condensate specific heat capacity [J/kg-K] D WM molecular diffusion coefficient of water in methane h B internal heat transfer coefficient [W/m 2 -K] h c external heat transfer coefficient [W/m 2 -K] h m mass transfer coefficient (m/s) k s solid deposit thermal conductivity [W/m-K] Gas mass flow rate [kg/s] Nu D Nusselt number Pr Prandtl number r c pipe outer radius [m] r i solid front radius [m] r w pipe inner radius [m] Re D Reynolds number q r Condensate to cooling fluid energy [W] T B Bulk condensate temperature [K] T c Cooling fluid temperature [K] T in Entering fluid Temperature [K] T out Exiting fluid Temperature [K] S c Schmidt number Sh D Sherwood number u' combined heat transfer coefficient [W/m 2 -K] ρ s solid deposit density [kg/m 3 ] ΔH f latent heat of solid formation [J/Kg] INTRODUCTION Major issues in flow assurance include plugging and deposition from hydrates, waxes, and asphaltenes. As the oil and gas industry gradually shifts towards hydrate management from prevention, a central question is whether fluids can be successfully produced by operating within the hydrate * Corresponding author: Phone: +1 (303) Fax +1 (303) asum@mines.edu

2 stability zone. Predicting hydrate formation and deposition in water saturated gas systems has direct application to gas export and sales pipelines. Dorstewitz and Mewes [1] published the first flowloop study investigating gas systems. Hydrates were formed at low pressures (~17 psia at 4 o C) using R-134a (1,1,1,2-tetrafluoroethane) in a horizontal pipe (inner diameter = 15 mm, length ~2 m). Experiments were carried out at 26% liquid loading fraction of liquids occupying the section volume). Hydrates were observed to first form on the pipe wall at the water-gas interface. The hydrate layer then grew along the pipe wall, until the entire perimeter of the pipe was covered with hydrates (Figure 1). This stenosis (inward growth of deposits) buildup on the pipe wall suggests a possible plugging mechanism in gas pipelines. Figure 2. Stenosis buildup of hydrates in SWRI flowloop [2]. and is also supported by analogous ice formation/plugging in water pipes [4]. A conceptual model for hydrate formation in gas condensate/gas-dominated systems is shown in Figure 3. In this model, hydrates first deposit on the pipeline wall and then grow. Due to fluid shear, sloughing of these deposits may occur. These particles can travel downstream, jam, and plug the entire line. Figure 1: Hydrate formation pattern in 15 mm test pipe [1]. The Southwest Research Institute (SWRI) in San Antonio, TX conducted a flow loop study, in which it had shown evidence of a stenosis build up of hydrates as well as formation in the bulk liquid in a horizontal 3-inch pipe, as shown in Figure 2 [2]. Nicholas [3] performed single-pass flowloop (285 feet length, 0.37 inch inner diameter) experiments with dissolved water in condensate. These were 100% liquid loading experiments with 90% of gas condensate, and 10% water. Uniform dispersed hydrate/ice deposition resulted from the dissolved water phase, with a slow pressure drop increase in a liquid condensate system. This stenosis (inward growth of deposits) buildup on the pipe wall suggests a possible plugging mechanism in gas pipelines (Figure 2). Figure 3. Conceptual picture for gas dominated / condensate systems (modified from [4]). The only recent laboratory work on hydrate formation in natural gas pipelines is of single particle deposition of propane hydrate with predictions using CFD modeling [5]. This, combined with the conclusion of a recent RPSEA meeting (March 9, 2009) identifying the most incidents of hydrate plugs being in gas-dominated systems, shows the urgency of studying in more detail the hydrate formation process in gas-dominated systems. Although the above mentioned flowloop experiments exist [1-3], no quantification of hydrate deposition has been fully explored on a laboratory scale. In annular flow of water-saturated natural gas, it is possible that water condenses out of the vapor phase on the walls. In the hydrate formation region, a key uncertainty in gas pipelines is whether or not hydrates deposit on the pipe wall [6]. If so, what is the mechanism? In this work, we report

3 laboratory observations of hydrate deposition on a cold surface and propose a mechanism for it. We also discuss a first-pass model to predict the hydrate deposition thickness from water-saturated methane vapor. EXPERIMENTAL SETUP & PROCEDURE Before constructing the high-pressure assembly for hydrates deposition for natural gas, we performed preliminary tests for frost deposition. The purpose of these tests was to have a frost system analog to hydrate deposition, and to aid in setting up hydrate deposition experiments. Frost Deposition As illustrated in Figure 3, compressed air at about 30 psig was saturated by bubbling it through a cylindrical water saturator, initially containing 300 ml of water. This saturated air was passed through the flash drum to separate any liquid droplets that formed during the saturation process. This avoided any free water in the Jerguson cell. After that, air flowed through the pipe that was connected to the Jerguson visual cell (high pressure level gage). The entire system was kept inside the water bath. A 1/8 stainless steel pipe was placed in the center of the Jerguson cell, which was used as the surface to deposit frost/hydrates. Figure 3. Schematic of frost deposition apparatus. Hydrate deposit was expected to grow outward on the surface. Although this is different from wall growth and stenosis build up, it was easier to setup and observe the deposit. The inner tube was cooled down to various sub-zero temperatures ranging from -5 to -15 o C. The Jerguson cell had a 1 inch by 1 inch square shaped cross-section with an axial length of 9.5 inch. The saturated air flowed from right to left with water droplets condensing and ice nucleating on the inner tube. The entire experiment was recorded with a video camera placed in front of the Jerguson cell. The major variables studied were air flow rate ranging from SLPM, saturation temperature of air was varied from o C (water bath temperature) and degree of subcooling of 5-15 o C (difference between deposition and equilibrium temperatures). Hydrate Deposition There were two main differences in the hydrate deposition setup and procedure as compared to the frost: 1) methane (CH 4 ) was used as the carrier fluid and 2) the system was operated under high pressure ( psig). In these experiments, methane gas (ultra high Purity, 99.99% research grade) was re-circulated in the system by two high-pressure 1000 HL series ISCO pumps operated in tandem for continuous flow. Figure 4. Process flow diagram of hydrate deposition apparatus. The Jerguson cell is rated to 3000 psi at 100 o F. The ISCO pumps are rated to 2000 psi at 190 ml/min of flow rate. The pressure gauge was placed between the flash drum and the Jerguson cell inlet. Two check valves were placed at the inlet and the outlet of each pump. The pumps operated such that when pump A was in the empty mode, pump B was in the refill mode, thus maintaining a constant volume in the system (Figure 4). Initially, the entire system was vented to remove any gaseous impurities through the vacuum pump. Water was charged through valve V1 to fill the saturator (~300 ml). The system was then pressurized with methane to the operating pressure ( psig). The water bath temperature was kept at the saturation temperature varying from o C. The chiller controlling the temperature of the coolant inside the inner tube was set at the deposition temperature varying from -10 to 2 o C. A continuous flow of gas was maintained in the system, which over the set period becomes saturat-

4 ed by passing through the saturator. The outer surface of the inner pipe was the cold spot where the hydrate nucleated. Hydrate nucleation occurred stochastically at different points along the surface of the inner pipe. To overcome the difficulties associated with hydrate nucleation, the inner pipe temperature was dropped to subzero temperatures (-10 to -5oC). The temperature was then increased above the ice formation temperature after nucleation ensuring that hydrates were present. RESULTS AND DISCUSSION Frost Studies The three stages of frost deposition [7] were observed in the experiments, as shown in Figure 5. After ice nucleation, rapid dendritic growth of ice crystals occurred. This was followed by the growth of a porous deposit, which annealed over time to become a more uniform and non-porous frost deposit. temperature was held at 10 oc, the gas flow rate was 0.4 ft/sec, and the inner tube was kept at -15oC providing a subcooling of 15 oc. Experimental volume of frost was visually determined to be 82 mm3 after 24 hours of frost deposition. Hydrate Studies The hydrate deposition experiments showed similar stages to frost deposition, as shown in the Figure 6. Hydrates continued to grow on the cold tube until the hydrate surface temperature equaled the hydrate equilibrium temperature. The different stages for hydrate deposition were: 1) Initial crystal growth Hydrate nucleation occurred at a random location along the pipe and slowly covered the entire surface of the pipe. 2) Hydrate growth period Hydrate crystals grew outward from the pipe surface. It can be seen from Figure 6(b) that the deposit is relatively porous in this period. Dendritic growth was not as prominent as in frost deposition because of the difference in saturation levels of water in methane (~300 ppmw) compared to air (~20,000 ppmw). 3) Annealing of hydrate As the surface temperature of the deposit reached the hydrate equilibrium temperature, hydrates ceased to form. Meanwhile water started condensing out, filling in the pore spaces and making the deposit nonporous. a. Initial Crystal growth (45 min) Figure 5. Picture of frost deposition on cold tube (a) Initial crystal growth, (b) frost growth period and (c) frost annealing period. The frost-annealing period arises when the surface temperature becomes equal to the water triple-point temperature due to increased frost thermal resistance. Water vapor condensing at the top of the frost layer forms a film that soaks into the frost layer, and freezes in the colder areas towards the cold wall. Then, a cyclic process of melting, freezing and growth occurs until thermal equilibrium of the entire frost layer is reached [8] equilibrium temperature. This continuous cycle of melting and freezing fills the pore spaces making the deposit grow from porous to relatively nonporous. In this particular experiment, the bath b. Hydrate growth period (10 hours) c. Annealing of hydrate (42 hours) Figure 6. a) Initial crystal growth, b) hydrate growth period, and c) annealing of hydrate with water droplets squeezing out of the deposit. Water on the surface of the deposit can be seen in the Figure 6(c). This shows that over a

5 period of 30 hours (in this experiment) hydrates started to anneal and become very hard. This can happen during the shutdown of a pipeline and the deposit can harden over the period. This type of hard plug stuck to the pipe wall would be much more harmful than a soft (porous) plug. 789:52"4//6" '" +" &" *" %" )" $" (" #$%&' ()*+,-&..' ( $ ) % * &,.52"4-8:;36" (#'" (#&" (#%" (#$" #'" #&" #%" #$" Figure 7. Hydrate deposit thickness and volume from experimental measurements. Figure 7 shows the thickness of the hydrate deposit over the course of the experiment. In this experiment, the pump flow rate was 190 ml/min (0.1ft/s), bath temperature of 25 o C and starting pressure of 1530 psig. Increase in the thickness of the deposit is rapid during the nucleation and growth period, but ceases towards the end where hardening of the deposit occurs. These experiments are repeatable in terms of visual observation of deposition with the change in pressure, flow rate, as well as saturation levels. The equilibrium temperature at 1500 psig for this system is 13 o C. Steady state can be assumed at the hydrate and bulk methane interface. Figure 8 shows the calculated temperature profiles inside hydrate deposit with porosities ranging from 0-50%. Also with the assumption of 50% porosity we see that we are within 1.5 o C of dissociation temperature. Also with decrease in porosity we see that surface temperature decreases, therefore providing conditions for further hydrate growth. $" (",-./01233"4556" Temperature ( o C) '#" ' &" %" $" #" /#"$%&%'()*" (#)" ()" (*)" '" '(#)" '()" '(*)" Hydrate Thickness(mm) Figure 8. Pseudo steady-state temperature profile in hydrate layer (thickness measured from cold pipe surface). Modeling All saturated phase deposition mechanisms have similar characteristics. The depositing component(s) must diffuse from the bulk phase to the surface and the latent heat of crystallization must be removed through the plate/pipe wall. An analogy can be drawn with wax deposition for hydrate deposition. In the current model, an approach similar to Singh [8] is used and the solid deposit is modeled using basic heat and mass balances. Three major assumptions in the methane hydrate formation model are: (1) the methane hydrate deposit formed is considered to be of constant porosity, (2) the pressure is assumed constant throughout system, and (3) Joule-Thompson effects are neglected. Also one-dimensional radial heat transfer is assumed. The temperature profile is calculated using an energy balance, assuming the cooling fluid is maintained at a constant temperature, # = #"$%&%'()*" +#"$%&%'()*",#"$%&%'()*" -#"$%&%'()*".#"$%&%'()*" (1) A series of convective resistances (neglecting conduction through the pipe wall) is used to calculate q r as illustrated in Figure 9.

6 Figure 9. Schematic of pipe-in-pipe flowloop configuration and the internal and external convective resistances in series [3]. The simulation results for frost deposition showed the predicted volume of frost deposited to be 77 mm3. This value is in good agreement with the actual volume of frost formed and hence it gives some assurance when applied to hydrate deposition. &#$" The internal heat transfer coefficient, hb, is calculated using the Chilton-Colburn analogy [9], (2) Changes in hydrate/ice thickness are calculated using mass balance on the water phase, and the surface temperature comes from energy balance across the control volume. # + # = "#$#%&'()* 2 ℎ = (3) The mass transfer coefficient is calculated analogous to the heat transfer coefficient, / ℎ = / = (4) The two unknowns in previous equations are ri and Ti. Ti was calculated using an energy balance across the control volume 2 ℎ 2 2 ℎ = 0 = ( ) + (5) (6) This model is used to model both frost and hydrates deposition. For hydrate deposition some additional considerations are required to the model, such as the geometry of the system, since in the present systems, deposition occurs outwards from the cold surface, whereas in an actual pipeline, deposition would happen inward from cold surface. Hydrate Thickness (mm) / = / = 2 Days &" Experimental thickness %#$" 1 Days %" #$" 0 Days Pipe Length (cm) Figure 10. Deposition model results showing hydrate thickness around the cold tube at the end of 1 and 2 days. Since methane holds significantly lower concentrations of water, difference can be expected between frost and methane deposit thickness. Figure 10 shows the simulated results from the model of hydrate thickness along the cold pipe after 2 days. Experimental thickness was found to be about 1.5 mm during the deposition experiment (Figure 7). The predicted thickness is on the same order of magnitude of the experimental thickness. This model can be extended to investigate a subsea methane pipeline, which is a more typical industrial scenario. The basic heat and mass transfer phenomena are expected to be similar to frost deposition and should scale accordingly with updated fluid properties. The incipient methane hydrate formation temperature at 1000 psia is 9.5oC (282.5 K) with a hydrate equilibrium water concentration of 138 ppmw. In deep waters, the pipeline temperature is around 4 oc. Hence any saturation of gas above the equilibrium concentration will allow for methane hydrate deposition on the cold pipe wall surface. Simulations with pipeline geometry of 100 km and

7 inner diameter of 0.61 m are used to study the effect of water saturation and velocity. Thickness (mm) % $#" $ #" % & ' ( $ $% Distance (Km) #$%" &"#$%" '"#$%" ("#$%" Figure 11. Hydrate deposit thickness along the pipe at different velocities, 1000 psia, 250 ppmw. Figure 11 shows the results from the simulations for the thickness of the deposit for increasing fluid velocity, which has minor impact in the deposit thickness, but does push the plug further downstream. Similarly, Figure 12 shows that with increasing saturation levels, the deposit thickness increases and plugging can occur early in the pipeline. Thickness (mm) % $#" $ #" 125 PPMW 150 PPMW 200 PPMW 250 PPMW % & ' ( $ $% Distance (Km) Figure 12. Hydrate deposit thickness along the pipe at different saturations, 1000 psia, 2m/s. CONCLUSIONS With a basic understanding from frost deposition experiments, preliminary experiments on hydrate growth from water-saturated gas systems were performed. These preliminary experiments have provided a lot of insight into the formation, deposition and plugging mechanisms in gas dominated systems. Preliminary work suggests that hydrate deposition on the pipe/chamber/cold surface wall is possible in gas systems. Deposition follows similar stages as in frost deposition, starting from nucleation to dendritic growth to annealing/hardening of the deposit. A coupled heat and mass transfer deposition model was used for frost, which was consistent with the experimental volumetric deposition. Initial hydrate deposition model results are also on the same order of magnitude of experimental data. Through modeling, it is also observed that a decrease in the hydrate porosity decreases the surface temperature of the hydrate deposit. The model shows an increase in hydrate thickness and a decrease in the distance of plug formation length with an increase in saturation and a decrease in velocity of fluids. REFERENCES [1] Dorstewitz F, Mewes D. The Influence of Hydrate Formation on Heat Transfer in Gas Pipelines. In: 6th Int. Symp on Transport Phenomenain Thermal Engineering, Seoul, Korea, [2] Hatton, G.J, Kruka V.R. Hydrate Blockage Formation - Analysis of Werner Bolley Field Test Data. Tech. rept. DeepStar CTR [3] Nicholas, J., Hydrate deposition in water saturated liquid condensate pipelines. Ph.D. thesis, Colorado School of Mines, [4] Lingelem M.N, Majeed A. I, Stange E. Industrial Experience in Evaluation of Hydrate Formation, Inhibition and Dissociation in Pipeline Design and Operation. In: Int. Conf. on Nat Gas Hydrates, NYAS, eds. Sloan, Happel, and Hnatow, 715, [5] Jassim E, Abedinzadegan Abdi M, Muzychka Y. A new approach to investigate hydrate deposition in gas-dominated flowlines. Journal of Natural Gas Science and Engineering. In press, Corrected Proof [6] Matthews P, Creek J, Ballard A, Rhyne L, Talley L, Hernandez O.C, Koh C, Sloan E. D, Chitwood J. Personsal communication - Disscussing a Gas Dominated Hydrate Plugging Model. Houston, TX. February 2, 2006.

8 [7] Hayashi Y, Aoki A, Adachi S, Hori, K. Study of Frost Properties Correlating with Formation Types. Journal of Heat Transfer, , [8] Le Gall, R., and Grillot, J.M Modeling of Frost Growth and Densification. International Journal of Heat and Mass Transfer, 40(13), [9] Singh P, Venkatesan R, Fogler S.H. Formation and Aging of Incipient Thin Film Wax-Oil Gels. AICHE J., (5), [10] Incropera F.P, Dewitt D.P. Fundamentals of Heat and Mass Transfer. 4th edn. John Wiley and Sons Inc., ACKNOWLEDGEMENTS We thank current and past Hydrate Busters for their extended help and constructive critique on this project. We acknowledge the support from the CSM Hydrate Consortium, which is presently sponsored by BP, Chevron, ConocoPhillips, ExxonMobil, Nalco, Petrobras, Shell, SPT Group, Statoil, and Total.

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