∗ * Corresponding author: Phone: +1 (303) 273 3873 Fax +1 (303) 273 3730 E-mail: asum@mines.edu

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 80401 UNITED STATES OF AMERICA

ABSTRACT One of the major issues in flow assurance includes plugging due to hydrate formation and deposi-tion. A key uncertainty in gas pipelines is hydrate deposition on the pipe wall. This work demon-strates hydrate formation and deposition on a cold surface in water-saturated gas systems. Me-thane hydrate deposition can be achieved in a laboratory-scale apparatus by nucleation of hy-drates from the gas phase on the outer surface of a cold tube. This indicates that wall hydrate dep-osition is possible in saturated systems. The deposit progresses from the initial nucleation to crys-tal growth to hardening (annealing) stages, growing from initially a porous to a relative non-porous 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 equi-librium temperature. A deposition model, which has been used for frost, matches well with exper-imental 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 Cp Condensate specific heat capacity [J/kg-K] DWM molecular diffusion coefficient of water in methane hB internal heat transfer coefficient [W/m2-K] hc external heat transfer coefficient [W/m2-K] hm mass transfer coefficient (m/s) ks solid deposit thermal conductivity [W/m-K] ! Gas mass flow rate [kg/s] NuD Nusselt number Pr Prandtl number rc pipe outer radius [m] ri solid front radius [m] rw pipe inner radius [m] ReD Reynolds number qr Condensate to cooling fluid energy [W]

TB Bulk condensate temperature [K] Tc Cooling fluid temperature [K] Tin Entering fluid Temperature [K] Tout Exiting fluid Temperature [K] Sc Schmidt number ShD Sherwood number u' combined heat transfer coefficient [W/m2-K] ρs solid deposit density [kg/m3] ΔHf latent heat of solid formation [J/Kg] INTRODUCTION Major issues in flow assurance include plugging and deposition from hydrates, waxes, and asphal-tenes. As the oil and gas industry gradually shifts towards hydrate management from prevention, a central question is whether fluids can be success-fully produced by operating within the hydrate

Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011), Edinburgh, Scotland, United Kingdom, July 17-21, 2011.

stability zone. Predicting hydrate formation and deposition in water saturated gas systems has di-rect 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 oC) 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 hy-drate layer then grew along the pipe wall, until the entire perimeter of the pipe was covered with hy-drates (Figure 1). This stenosis (inward growth of deposits) buildup on the pipe wall suggests a pos-sible plugging mechanism in gas pipelines.

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) experi-ments with dissolved water in condensate. These were 100% liquid loading experiments with 90% of gas condensate, and 10% water. Uniform dis-persed hydrate/ice deposition resulted from the dissolved water phase, with a slow pressure drop increase in a liquid condensate system. This steno-sis (inward growth of deposits) buildup on the pipe wall suggests a possible plugging mechanism in gas pipelines (Figure 2).

Figure 2. Stenosis buildup of hydrates in SWRI

flowloop [2].

and is also supported by analogous ice for-mation/plugging in water pipes [4]. A conceptual model for hydrate formation in gas conden-sate/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 3. Conceptual picture for gas dominated /

condensate systems (modified from [4]).

The only recent laboratory work on hydrate for-mation 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 ex-periments 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 wheth-er or not hydrates deposit on the pipe wall [6]. If so, what is the mechanism? In this work, we report

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 hy-drate 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 out-

ward 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 temper-atures ranging from -5 to -15 oC. 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 con-densing and ice nucleating on the inner tube. The entire experiment was recorded with a video cam-era placed in front of the Jerguson cell. The major variables studied were air flow rate ranging from

1.7-3 SLPM, saturation temperature of air was varied from 10-20 oC (water bath temperature) and degree of subcooling of 5-15 oC (difference be-tween 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 (CH4) was used as the carrier fluid and 2) the system was operated under high pressure (1000-1600 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 operat-ed in tandem for continuous flow.

Figure 4. Process flow diagram of hydrate deposi-

tion apparatus.

The Jerguson cell is rated to 3000 psi at 100 oF. 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 op-erated such that when pump A was in the empty mode, pump B was in the refill mode, thus main-taining a constant volume in the system (Figure 4).

Initially, the entire system was vented to re-move any gaseous impurities through the vacuum pump. Water was charged through valve V1 to fill the saturator (~300 ml). The system was then pres-surized with methane to the operating pressure (1000-1600 psig). The water bath temperature was kept at the saturation temperature varying from 10-30 oC. The chiller controlling the temperature of the coolant inside the inner tube was set at the deposition temperature varying from -10 to 2oC. A continuous flow of gas was maintained in the system, which over the set period becomes saturat-

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 nuclea-tion ensuring that hydrates were present. RESULTS AND DISCUSSION Frost Studies The three stages of frost deposition [7] were ob-served 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 de-posit.      

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 to-wards 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 non-porous. In this particular experiment, the bath

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 simi-lar stages to frost deposition, as shown in the Fig-ure 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 oc-

curred 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 tempera-ture of the deposit reached the hydrate equilib-rium temperature, hydrates ceased to form. Meanwhile water started condensing out, filling in the pore spaces and making the deposit non-porous.

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

a. Initial Crystal growth (45 min)

b. Hydrate growth period (10 hours)

c. Annealing of hydrate (42 hours)

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.

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 25oC 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 experi-ments 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 oC.

Steady state can be assumed at the hydrate and bulk methane interface. Figure 8 shows the calculated temperature profiles inside hydrate de-posit with porosities ranging from 0-50%. Also with the assumption of 50% porosity we see that we are within 1.5 oC of dissociation temperature. Also with decrease in porosity we see that surface temperature decreases, therefore providing condi-tions for further hydrate growth.

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 compo-nent(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 analo-gy can be drawn with wax deposition for hydrate deposition. In the current model, an approach simi-lar 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 de-posit formed is considered to be of constant po-rosity, (2) the pressure is assumed constant throughout system, and (3) Joule-Thompson ef-fects 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 tempera-ture, !!"# = !!" −

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hydrates deposition. For hydrate deposition some additional considerations are required to the mod-el, 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 sur-face.

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.

Figure 10. Deposition model results showing hy-

drate thickness around the cold tube at the end of 1 and 2 days.

Since methane holds significantly lower concen-trations of water, difference can be expected be-tween 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 trans-fer phenomena are expected to be similar to frost deposition and should scale accordingly with up-dated 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

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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 down-stream. Similarly, Figure 12 shows that with in-creasing saturation levels, the deposit thickness increases and plugging can occur early in the pipe-line.

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, depo-sition 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 anneal-ing/hardening of the deposit.

A coupled heat and mass transfer deposition model was used for frost, which was consistent with the experimental volumetric deposition. Ini-tial hydrate deposition model results are also on the same order of magnitude of experimental data. Through modeling, it is also observed that a de-crease in the hydrate porosity decreases the surface temperature of the hydrate deposit. The model shows an increase in hydrate thickness and a de-crease 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 Hy-drate Formation on Heat Transfer in Gas Pipe-lines. In: 6th Int. Symp on Transport Phenomenain Thermal Engineering, Seoul, Korea, 1993. [2] Hatton, G.J, Kruka V.R. Hydrate Blockage Formation - Analysis of Werner Bolley Field Test Data. Tech. rept. DeepStar CTR 5209-1. 2002 [3] Nicholas, J., Hydrate deposition in water satu-rated liquid condensate pipelines. Ph.D. thesis, Colorado School of Mines, 2008. [4] Lingelem M.N, Majeed A. I, Stange E. Indus-trial Experience in Evaluation of Hydrate For-mation, Inhibition and Dissociation in Pipeline Design and Operation. In: Int. Conf. on Nat Gas Hydrates, NYAS, eds. Sloan, Happel, and Hnatow, 715, 75. 1994. [5] Jassim E, Abedinzadegan Abdi M, Muzychka Y. A new approach to investigate hydrate deposi-tion in gas-dominated flowlines. Journal of Natural Gas Science and Engineering. In press, Corrected Proof. 2010 [6] Matthews P, Creek J, Ballard A, Rhyne L, Talley L, Hernandez O.C, Koh C, Sloan E. D, Chitwood J. Personsal communication - Disscuss-ing a Gas Dominated Hydrate Plugging Model. Houston, TX. February 2, 2006.

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[7] Hayashi Y, Aoki A, Adachi S, Hori, K. Study of Frost Properties Correlating with Formation Types. Journal of Heat Transfer, 1977. 99, 239–245. [8] Le Gall, R., and Grillot, J.M. 1997. Modeling of Frost Growth and Densification. International Journal of Heat and Mass Transfer, 40(13), 3177–3187. [9] Singh P, Venkatesan R, Fogler S.H. Formation and Aging of Incipient Thin Film Wax-Oil Gels. AICHE J., 2000. 46(5), 1059–1074. [10] Incropera F.P, Dewitt D.P. Fundamentals of Heat and Mass Transfer. 4th edn. John Wiley and Sons Inc., 1996. 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, Exx-onMobil, Nalco, Petrobras, Shell, SPT Group, Statoil, and Total.