Developing a Comprehensive Understanding and Model of Hydrate in

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Developing a Comprehensive Understanding and Model of Hydrate in Multiphase Flow: From Laboratory Measurements to Field Applications Amadeu K. Sum,* Carolyn A. Koh, and E. Dendy Sloan Center for Hydrate Research, Chemical and Biological Engineering Department, Colorado School of Mines, Golden, Colorado 80401, United States ABSTRACT: Gas hydrates pose a major flow assurance problem in the production and transportation of oil and gas. Managing the formation of gas hydrates is central for safe and continuous operation. In this paper, we will provide an overview of the Center for Hydrate Research and its efforts toward a better understanding of the formation, agglomeration, and accumulation of hydrates in multiphase flow. This paper will discuss the projects in the Center for Hydrate Research aimed at quantifying how hydrates can be managed by first understanding the fundamental processes for nucleation, growth, agglomeration, deposition, and plugging, knowledge in these areas that has been accumulated over decades of research. While still a work in progress, significant advances have been made in describing the hydrate formation in oil-dominated, water-dominated, and gas-dominated systems. One of the end goals of our effort is to develop the knowledge and tools to manage hydrates, as opposed to avoidance, in the production and transportation of oil and gas. It is recognized that the ideas and concepts introduced here are solely based on the efforts at the Center for Hydrate Research with direct input from industry leaders in the field over decades; as such, there may be alternative views on the problem, but these are not considered here. However, the authors do not know of any published models that provide transient, multiphase prediction of hydrates in a flowline.

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INTRODUCTION Gas hydrates play a significant role in the flow assurance of oil and gas flowlines, posing one of the most serious problems relative to the formation and deposition of other solids (e.g., wax, asphaltenes, scale, etc.). The formation of gas hydrates in flowlines can be not only fast but also in large volumes, causing unexpected operational problems.1 Industry has traditionally taken the approach of preventing gas hydrates from forming in flowlines by injection of a socalled thermodynamic inhibitor (THI, e.g., methanol or monoethylene glycol), which inhibits hydrate formation in the free water. As seen in Figure 1, in this approach, the THI shifts the hydrate equilibrium curve to more severe temperature and pressure conditions, thus allowing the flowline to operate

outside the hydrate stability region. While effective in preventing hydrate formation, the costs and quantity of chemical required can be significant.2 Over the last 25 years, the industry has looked for an alternative approach to the complete prevention of gas hydrates in flowlines by shifting to a management strategy of hydrates, that is, to allow hydrates to form in flowlines but preventing their agglomeration to form a blockage.3 Such a strategy would allow the industry to tolerate hydrates in the flowlines and reduce the cost and quantity of chemicals used in their operations. Using this approach, it is therefore important to have a good understanding of how hydrates form, agglomerate, deposit, and jam in a flowline, so that one can assess the risk of hydrates in the flowlines and the potential for a blockage to form. This approach has been implemented to some extent in the last few decades in the industry with the use of antiagglomerants (AAs) and low-dosage hydrate inhibitors (LDHIs).

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LABORATORY-SCALE MEASUREMENTS The formation and transport of hydrate in flowlines are perhaps the most complex multiphase flow problems, involving gas, liquid hydrocarbon, water, and hydrates as solids. One conceptual view (on the basis of the work at CSM over decades of research and input from industry leaders in the field) on how hydrates may form and agglomerate to a blockage in Special Issue: Upstream Engineering and Flow Assurance (UEFA) Figure 1. Example schematic of a pressure−temperature trace for a field and the corresponding hydrate equilibrium boundaries with and without methanol as THI in the free water phase. © 2012 American Chemical Society

Received: February 1, 2012 Revised: April 17, 2012 Published: April 22, 2012 4046

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flowlines containing gas, oil, and water is shown in Figure 2, which illustrates the following major processes: (1) Before

The conceptual model described in Figure 2 can be said to be applicable to oil- and water-dominated systems. When considering gas-dominated systems, the main hydrate formation mechanism is deposition on the pipe wall, as shown in Figure 3. These deposits can gradually grow, over prolonged

Figure 2. Conceptual model for hydrate formation, agglomeration, and plugging in a multiphase flow system consisting of gas, oil, water, and hydrates (adapted from Turner,4 who originally developed this picture with the input from J. Abrahamson, University of Canterbury, Christchurch, New Zealand). Figure 3. Conceptual model for hydrate formation and plugging in a gas-dominated multiphase flow system.

hydrates are formed, the phases are emulsified from the flow turbulence, possibly creating gas bubbles entrained in the oil and water, oil emulsified in water, and water emulsified in oil. The emulsified/entrained droplets/bubbles create the surface area for hydrate formation. (2) When the temperature and pressure conditions are within the hydrate stability region, hydrate will most likely form at the interface between the water and hydrocarbon fluid (oil or gas), forming a hydrate shell around the water/oil droplets emulsified in oil/water. (3) Another possible location for hydrates to initially form is on the pipe walls, because these will be wet and constantly exposed to the gas. The deposition of hydrates on the pipe wall will be discussed later. (4) Hydrate growth will be limited by either the availability of water and gas or temperature. The initial hydrate shell (∼30−50 μm thick5) is probably formed very quickly, because the kinetics of hydrates is known to be quite fast, given that the right components (water and gas) are present for formation. Soon after, the process for continued hydrate growth is typically mass-transfer- or heat-transfer-limited. In the former, water and/or gas must diffuse to the interface, and in the latter, heat must be removed because the hydrate formation is an exothermic (heat released) process.6 (5) Once a sufficient amount of hydrates is in the system, the hydrate slurry will change the rheology (flow behavior) of the system,7 with hydrate either suspended in the fluid phase or deposited on the solid surface. (6) Once hydrates are present, the hydrate particles may interact to agglomerate into larger aggregates or continually grow on the existing deposits on the pipe wall. The interaction of hydrate particles will largely depend upon the continuous fluid phase. If the hydrate particles are dispersed in a water-continuous phase, the binding force between the hydrate particles is minimal, and they will remain dispersed. If the particles are dispersed in an oil-continuous phase, it is likely that the particles will bind to form large aggregates because of the water capillary bridging formed between the particles. (7) Hydrate deposition on the wall is an important phenomenon, which may be responsible for eventual hydrate blockages under steady-state operation, because these deposits can slowly build up over time. Hydrate deposits on the wall can narrow the flow channel, similar to wax/asphaltene deposition. The mechanism for the continual hydrate deposition on the pipe wall is the matter of current efforts in our laboratory. (8) The last stage in this conceptual model is the jamming of hydrate particles, causing the blockage of the system. If we can understand how jamming occurs, then perhaps we can develop strategies to prevent the system from jamming.

periods of time, to narrow the flow channel and cause significant pressure drops in the system. These deposits can also detach from the wall (sloughing) because of the fluid shear, and the loose chunks of hydrates may eventually accumulate in a flow restriction (e.g., another hydrate deposit, valve, bend) and cause the system to jam. The conceptual models presented and the phenomena involved in the mechanisms for hydrate formation to plugging form the basis for much of the research that needs to be performed to develop a comprehensive model that will fully describe the dynamics and interactions of hydrate in multiphase flow. It is these conceptual models that have guided the research in the Center for Hydrate Research for over a decade and led to the development of the Colorado School of Mines (CSM) hydrate kinetics model (CSMHyK), which not only combines the concepts in Figure 2 but is also an actual model that is packaged to quantitatively predict the formation and plugging of hydrates in multiphase flow. The different phenomena in these models are projects that we are studying to better understand using laboratory measurements on the emulsification, hydrate nucleation and growth, hydrate slurry rheology, hydrate particles co-/adhesion, hydrate particle aggregation, hydrate deposition, and particle jamming. Figure 4 illustrates our research approach to understand and develop a comprehensive model for hydrates in multiphase

Figure 4. Multiscale approach and corresponding effort in the research for hydrates in the Center for Hydrate Research at the CSM. 4047

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Figure 5. Illustration of laboratory-scale measurements to probe phenomena associated with hydrate aggregation (top left), hydrate deposition on surfaces (middle left), hydrate slurry rheology (bottom left), hydrate particle cohesion (top right), and particle jamming (bottom right). Each of these areas corresponds to specific projects within the Center for Hydrate Research at the CSM.

Figure 6. Flowloop tests, such as those at the University of Tulsa and ExxonMobil, for hydrate formation are essential in advancing and bridging the knowledge developed at the laboratory scale. The plots illustrate the data measured in the flowloop and how they provide insight into the mechanisms for hydrate formation. Shown in the figure are the flowloop schematic (top left), conceptual model for hydrate formation in the waterdominated system based on pressure drop (middle left), generic growth rate expression for hydrates (bottom left), actual flowloop data measured (bottom right), and correlation for transition from homogeneous to heteregenous dispersion of hydrates (top right).

flow. At the bottom of the pyramid, we have the laboratoryscale measurements, which comprises the foundation and bulk of the experimental measurements performed. At the laboratory scale, the individual phenomena are studied, breaking down the problem into tractable and measurable experiments from which we can obtain a fundamental understanding and develop models that are transferable and translatable across different system conditions (composition, chemistry, temperature, pressure, etc.). Figure 5 gives an illustration of selected examples of specific phenomena that we probe at the laboratory scale. The phenomena illustrated in the figure are hydrate

particle cohesion, hydrate aggregation, hydrate deposition on surfaces, hydrate slurry rheology, and particle jamming. The plot for hydrate particle cohesion indicates that the cohesive forces are strongly dependent upon the bulk medium and the presence of a water layer on the particle.8 The schematic diagram for hydrate aggregation highlights the size, scale, and interactions of the particle-forming agglomerates. The image for hydrate deposition on surfaces is an example of deposition on a cold surface from a gas-saturated system, which initially forms a porous deposit and over time anneals to a nonporous hydrate layer.9 The plot for the hydrate slurry rheology shows the 4048

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Figure 7. CSMHyK−OLGA allows for the simulation of hydrate formation in multiphase flow, giving information into when, where, and how much hydrates are formed in flowlines (middle left). This tool considers steady-state and transient conditions and provides a means to assess the risk of hydrate in flowlines by measuring the pressure drop (middle right) and relative viscosity of the condensed phase (bottom).

allow us to benchmark the laboratory data/model and consider other mechanisms that may be manifested in response to hydrate formation and accumulation in the flowloop. In this example, our understanding of hydrates in high water cut systems has significantly advanced from the analysis of the flowloop pressure drop and formation rate data, resulting in a correlation for the transition from homogeneous to heterogeneous suspension of hydrates, which is a measure of conditions resulting in an eventual plug of the flowlines, and a hydrate growth model based on heat-transfer, mass-transfer, and kinetic limitations.12

viscosity response of water in crude oil emulsions (various water cuts) upon hydrate formation under continuous shearing of the system.10 The last set in the figure shows the principle of particle jamming as well as a representative plot for a jamming probability.11

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FLOWLOOP MEASUREMENTS One can obviously see the advantages of such an approach at the laboratory scale in segmenting the different phenomena into separate studies. In the one hand, such approach allows us to perform controlled experiments and isolate the effects of important variables in that one phenomenon. However, in doing so, we are also decoupling the interaction of the phenomena and perhaps not completely capturing what may happen in actual flowlines. For this reason, we also perform flowloop tests to consider all of the phenomena together to mimic as close as possible the scenario in the field of flowlines. The flowloop tests lie in the middle of the pyramid in Figure 4 and represent a smaller but significant portion of our research efforts. A flowloop facility is unavailable at CSM, and these tests are performed in collaboration with ExxonMobil and the University of Tulsa. In addition to being able to include all of the phenomena at play, the principal advantage of flowloop testing is the consideration of multiphase flow in the formation, aggregation, and plugging of hydrates. In the controlled type of experiments in the laboratory scale, most experiments are batch/semi-batch and, as such, cannot consider the multiphase flow aspect in the formation and agglomeration of hydrate. Figure 6 illustrates one example on how data from the flowloop

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MODELING AND CSMHYK At the top of the pyramid in Figure 4, representing the smallest component but perhaps the largest impact on our research efforts, is the synthesis and combination of all of the other components in the lower portions of the pyramid into CSMHyK, which, coupled with OLGA, allows us to assess the risk for hydrate formation in actual field scenarios. It is this component of our research that will eventually be used by the industry as a tool to evaluate when, where, and how much hydrate may form in multiphase flowlines. CSMHyK is an evolving model in our research efforts, which is constantly being improved on the basis of the knowledge from laboratory measurements and flowloop tests. Figure 7 illustrates the application of CSMHyK−OLGA in the risk assessment for hydrates in a field tieback from the wellhead to the platform.13 The figure shows representative data from the simulations indicating the fraction of the phases 4049

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Figure 8. Conceptual picture for hydrate deposition on the pipe wall. A thin water layer may exist on the pipe wall, which is exposed to the hydrocarbon fluid. Hydrate may initially form from this water layer and/or at the three-phase point of contact. Once hydrates begin to form, hydrates can continually accumulate to grow a large deposit that can narrow the flow channel and eventually cause the system to plug.

flow regime will specify how the phases are distributed and mixed. The flow regime is equally important after hydrates are formed, because the flow pattern will affect the distribution of hydrates among the phases and deposition along the flowlines. Multiphase flow also provides the connection of flow regimes to pressure drop, which is the variable used to assess the flow conditions in flowlines and is also the variable used to characterize potential hydrate problems in flowlines. As such, the ability of accurately predicting hydrate formation and blockage in flowlines will largely depend upon the multiphase flow modeling of the system, because the flow regime will have a large impact on where and how hydrates will form (mechanism of formation) and how they will be distributed in the flowline.17 While the understanding of hydrate formation and blockage in flowlines has matured, our knowledge is still lacking in many areas. As extensively discussed above, multiphase flow will remain a major component that will heavily influence how and where hydrates are formed and distributed in flowlines. Flowloop tests will continue to be invaluable in providing the closest data to the field and also scale up the learning from laboratory-scale experiments. In the laboratory scale, our understanding of the different phenomena will need to be furthered especially in the following areas: hydrate interfacial properties, hydrate particle aggregation, hydrate slurry rheology, and hydrate deposition (wall and suspended particles). For the hydrate interfacial properties, we recognize that all of the action happens at the interface between the water and hydrocarbon phases prior to hydrates being formed and on the hydrate and hydrocarbon interface after hydrates are formed. The principle of how AAs work is based on changes to the interfacial properties of hydrate particles, such that the particles will not stick and remain loosely dispersed in the fluid phase. This is an area that will continue to remain important as the concept of hydrate management gains more acceptance in the industry. One of the best tools available to probe specifically the interfacial properties is the micromechanical force apparatus, including a second generation that may consider studies at high pressure (further details on this method can be found elsewhere8,18). Hydrate particle aggregation is closely linked to the hydrate interfacial properties, but in this area, we still need to quantify the aggregation process and aggregate size under different shear conditions and interfacial chemistry. The current knowledge of hydrate slurry rheology is also superficial, and it is obvious that the rheological properties of the hydrate slurry are central in the management of hydrates in flowlines as well as shut-in and restart situations. The rheology of hydrate slurries is a challenging area because of the many technical difficulties in performing experiments that closely capture conditions in flowlines, such as the temperature, pressure, composition, emulsification/dispersion, and shear.

along the flowline, the pressure drop along different sections of the flowline, and the relative viscosity, which is a measure of the plugging tendency of the system (the reader is directed to another publication for an extensive discussion of the results shown in these plots13). In its present version, CSMHyK is capable of considering hydrate formation in an oil-dominated system (water emulsified in an oil continuous phase). Our current efforts in studying hydrate formation in high water cut systems will extend CSMHyK to consider hydrate formation in cases where a free water phase is present. Our goal is to add the capability in CSMHyK to consider hydrate formation in gasdominated systems, which would then include the most important type of systems encountered in flowlines.14 CSMHyK has been developed on the basis of experimental data and observations in the laboratory and flowloops. It is recognized that CSMHyK has not been “validated” with actual field data, because hydrate blockage in flowlines is not purposely formed, with the exception of two cases, the Tommeliten−Gamma and Werner−Bolley field tests.15 As such, to the best of our knowledge, the use of CSMHyK in the industry has been limited to after-the-fact cases (CSMHyK was used to understand how, when, and where hydrates formed after a hydrate plug had already formed and been removed) or in preliminary assessment of trouble spots in flowlines. The true test of CSMHyK will only come with time after several cases have been considered, not as a solution to hydrates in flow assurance, but as a tool for assessment of the risk of hydrates under different field and operating conditions.

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CHALLENGES FOR HYDRATES IN FLOW ASSURANCE One of the most important components affecting hydrate formation and blockage in flowlines is the multiphase flow aspect. Over the years, we have significantly advanced our knowledge and understanding of hydrate formation in different conditions, whether kinetically controlled, mass-transferlimited, or heat-transfer-limited. The multiphase flow aspect is not easily addressed at the laboratory scale, thus, the need of flowloop tests. However, the interpretation of the data on hydrate formation together with the multiphase flow is a challenging area that is largely limited by our understanding of multiphase flow alone. Multiphase flow itself is an active field of research, and the addition of hydrates (a solid phase) into the mix of oil, water, and gas only makes the problem more challenging.16 There are two components of multiphase flow that are critical when considering hydrates: one is the flow regime, and the other is the pressure drop in the system. The flow regime in the system is important in hydrate formation because it determines the contact and distribution of the phases. The formation of hydrates is controlled by the surface area of contact between the water and hydrocarbon phases, and the 4050

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Energy & Fuels Hydrate deposition is perhaps the most challenging area to be studied, because this phenomenon can slowly occur over long periods of time (weeks to months) for systems under continuous operation (single-pass). As illustrated in Figure 8, there are two deposition mechanisms that need to be considered: one involves the initial deposition of hydrates on a solid surface (e.g., wet pipe wall), film growth, and the other is the deposition of hydrates on an existent hydrate deposit on the solid surface. Both of these mechanisms requires a constant wetting of the surface (solid or hydrate), which in actual flowlines would indeed occur, because the surface is hydrophylic (water adsorbs readily on carbon steel). Because of the nature of how hydrate deposition may happen, a continuous flow system would be best suited in these studies and one in which the fluids and fluid composition were to remain relatively constant (single-pass flowloop). All of the learnings from these studies will be incorporated in CSMHyK to build a comprehensive model that accounts for the actual physics and chemistry in the hydrate formation and blockage in multiphase flow systems. The strategy we use to be able to translate the relevant phenomena to a form in CSMHyK is to (1) observe, (2) quantify, (3) generalize, and (4) model the phenomena. As a final note, the authors do recognize that the ideas and concepts presented here are biased from the work performed at the Center for Hydrate Research over decades and influenced by the input from industry leaders in the area of hydrates and flow assurance. To the best of our knowledge, there is no other model for hydrates in multiphase flowlines that provides such a comprehensive account of when, where, how, and how much hydrates may form in the complexity of gas/water/oil systems. As such, there may be alternate models and concepts for hydrates in flow assurance, and these, if available, would be a welcome addition to further our understanding of hydrates.

ACKNOWLEDGMENTS

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REFERENCES

The concepts and ideas presented have been developed over a number of years at the Center for Hydrate Research at the CSM, resulting from the research of current and past graduate students, postdoctoral researchers, visiting scholars, and faculty. We thank the following graduate students for their individual efforts over the past decade: Doug Turner, Simon Davies, Joseph Nicholas, John Boxall, Jason Lachance, Zach Aman, Matt Walsh, Sanjeev Joshi, Ishan Rao, Eric Webb, Patrick Lafond, Giovanny Grasso, and particularly, Luis Zerpa. Funding for the research in the center has benefited from the CSM Hydrate Consortium, comprised of current and past members: BP, Chevron, Champion Technologies, ConocoPhillips, ExxonMobil, Halliburton, Multi-Chem, Nalco, Petrobras, Schlumberger, Shell, SPT Group, Statoil, and Total.

(1) Natural Gas Hydrates in Flow Assurance; Sloan, D., Koh, C., Sum, A. K., Eds.; Elsevier: Amsterdam, The Netherlands, 2010. (2) Carroll, J. Natural Gas Hydrates: A Guide for Engineers; Gulf Publishing: Tulsa, OK, 2002. (3) Creek, J. L.; Subramanian, S.; Estanga, D. New methods for managing hydrates in deepwater tiebacks. Proceedings of the Offshore Technology Conference; Houston, TX, May 2−5, 2011. (4) Turner, D. Clathrate hydrate formation in water-in-oil dispersions. Ph.D. Dissertation, Colorado School of Mines, Golden, CO, 2005. (5) Taylor, C. J.; Miller, K. T.; Koh, C. A.; Sloan, E. D. Chem. Eng. Sci. 2007, 62, 6524. (6) Sloan, E. D.; Koh, C. A. Clathrate Hydrates of Natural Gases, 3rd ed.; CRC Press: Boca Raton, FL, 2008. (7) Camargo, R.; Palermo, T. Rheological properties of hydrate suspensions in an asphaltenic crude oil. Proceedings of the 4th International Conference on Gas Hydrates; Yokohama, Japan, May 19−23, 2002. (8) Aman, Z. M.; Joshi, S. E.; Sloan, E. D.; Sum, A. K.; Koh, C. A. J. Colloid Interface Sci. 2012, DOI: 10.1016/j.jcis.2012.03.019. (9) Rao, I.; Sloan, E. D.; Koh, C. A.; Sum, A. K. Laboratory experiments and modeling for hydrate formation and deposition from water saturated gas systems. Proceedings of the 7th International Conference on Gas Hydrates; Edinburgh, U.K., July 17−21, 2011. (10) Webb, E. B.; Rensing, P. J.; Koh, C. A.; Sloan, E. D.; Sum, A. K.; Liberatore, M. W. Energy Fuels 2012, in press. (11) Lafond, P. G.; Gilmer, M. W.; Koh, C. A.; Sloan, E. D.; Wu, D. T.; Sum, A. K. Measurements and modeling for three dimensional particle jamming as model for gas hydrates in pipelines. Proceedings of the 7th International Conference on Gas Hydrates; Edinburgh, U.K., July 17−21, 2011. (12) Joshi, S. Experimental investigation and modeling of gas hydrate formation in high water cut producing oil pipelines. Ph.D. Dissertation, Colorado School of Mines, Golden, CO, 2012. (13) Zerpa, L. E.; Sloan, E. D.; Sum, A. K.; Koh, C. A. Generation of best practices in flow assurance using a transient hydrate kinetics model. Proceedings of the Offshore Technology Conference; Houston, TX, May 2−5, 2011. (14) Zerpa, L. E.; Aman, Z. S.; Joshi, S.; Rao, I.; Sloan, E. D.; Koh, C. A.; Sum, A. K. Predicting hydrate blockages in oil, gas and waterdominated systems. Proceedings of the Offshore Technology Conference; Houston, TX, April 30−May 3, 2012. (15) Hatton, G. J.; Kruka, V. R. Hydrate Blockage Formation Analysis of Werner Bolley Field Test Data, DeepStar CTR 5209-1, 2002. (16) Danielson, T. J. A simple model for hydrodynamic slug flow. Proceedings of the Offshore Technology Conference, Houston, TX, May 2−5, 2011. (17) Zerpa, L. E.; Rao, I.; Aman, Z. M.; Sloan, E. D.; Koh, C. A.; Sum, A. K. Extension of a simple hydrodynamic slug flow model for

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CONCLUSION The field of hydrates in flow assurance has significantly matured over the last several years, in large part from the broader understanding of the phenomena involved in the formation and accumulation of hydrates in multiphase flow. The mechanisms for these phenomena can be well-studied in isolation at the laboratory scale, which has been the strength of our research center at the CSM since 1975. However, it is the coupling of the knowledge at the laboratory scale with flowloop tests that provide the most important connection to actual field conditions. The flowloop tests are also essential in transferring the fundamental knowledge from laboratory measurements into realistic models, because the tests in the flowloop combine all of the phenomena studied in the laboratory scale plus the important influence of multiphase flow. One of our goals is to package all of the knowledge learned from laboratory and flowloop scales into a comprehensive model (CSMHyK) that can be used to predict when, where, and how much hydrates are formed and assess the risk for hydrate formation and accumulation in multiphase flowlines.

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AUTHOR INFORMATION

Corresponding Author

*Telephone: +1-303-273-3873. Fax: +1-303-273-3730. E-mail: [email protected]. Notes

The authors declare no competing financial interest. 4051

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transient hydrate kinetics. Proceedings of 8th North American Conference on Mutliphase Technology; Banff, Canada, June 20−22, 2012. (18) Aman, Z. A.; Brown, E. P.; Sloan, E. D.; Sum, A. K.; Koh, C. A. Phys. Chem. Chem. Phys. 2011, 13, 19796.

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