PB Oil and Gas Facilities • April 2014 April 2014 • Oil and Gas Facilities 67

SummaryWater condensation and/or hydrate formation at the top of pipe-lines are serious design/operation considerations in pipelines with stratified flow. Water condensation could result in top-of-the-line corrosion, particularly in sour-gas systems. Hydrate forma-tion is believed to be another serious risk if the inhibitor in the aqueous phase cannot protect against hydrate formation at the top of the pipeline.

In this paper, we report the results of some preliminary tests con-ducted in a new experimental setup constructed for investigating gas-hydrate risks in various operational scenarios (e.g., top of pipe-lines, deadlegs/jumpers, startups, shutdowns). The reported three series of tests conducted in the new experimental setup address hy-drate-formation risks at the top of pipelines or deadlegs caused by temperature gradient, and the risk of hydrate formation in the gas phase in the presence of kinetic hydrate inhibitors (KHIs) during pipeline cool down and startup. The results provide a better evalua-tion of the risks involved in various systems and provide guidelines for avoiding the associated problems.

IntroductionGas-hydrate management is considered to be the most critical as-pect of flow-assurance-design strategies because hydrate plugs can have major safety and economic impacts on flowline operation and can stop production completely for several days or months, and in the worst case, can result in pipeline abandonment. Hydrate-plug dissociation and remediation can be a costly and time-consuming process and can result in restrictions on system operations. The is-sues of hydrate prevention and (if needed) remediation are there-fore very important. Current methods for avoiding gas-hydrate problems are generally based on one or a combination of the fol-lowing three techniques: (1) injection of thermodynamic inhibitors (e.g., methanol, ethanol, monoethylene glycol) to prevent hydrate formation, (2) use of KHIs to sufficiently delay hydrate nucleation/growth, and (3) maintaining pipeline operating conditions outside the hydrate-stability zone (HSZ) by removing one of the elements required for hydrate formation. Currently, the most common hy-drate-flow-assurance strategy is to rely on the injection of organic inhibitors (e.g., methanol, monoethylene glycol) or KHIs to inhibit hydrate formation in gas production and transportation. The cur-rent industry practice for hydrate prevention by chemical methods is to inject hydrate inhibitors at the upstream end of pipelines on the basis of the calculated/measured hydrate-phase boundary, water cut, worst-case pressure and temperature conditions, and the pos-sible inhibitor loss to nonaqueous phases.

With this approach, the required dosage of inhibitors is injected into the pipelines to prevent hydrate formation in the system. Using this approach, most of the pipelines/flowlines should be completely inhibited by these chemicals; however, a few unknown blockages resulting from hydrates are reported. It is still relatively unclear if there is a possibility of hydrate formation in the gas phase because of the water condensation or the amount of water dissolved in the gas phase (Lunde et al. 2012; Kinnari er al. 2008).

The main objective of this new work is to study the possibility of hydrate formation on top of subsea, stratified-multiphase-flow transmission pipelines for various fluid systems with and without inhibitors (i.e., KHIs having low vapor pressure; hence, not enough inhibitor in the gas phase). In this work, three series of tests have been conducted to evaluate the risk of hydrate formation at the top of the pipeline from condensed water and chemically treated water under stratified-flow conditions. The first test was conducted at the worst hydrate-formation condition (i.e., with fresh water) to ex-amine whether hydrate can form in the gas phase because of water condensation resulting from temperature gradient. The results of this test were very promising and showed that the concept was fea-sible. Thus, the industry needs to conduct further investigations on hydrate formation in the gas phase to ensure unimpeded flow from source to end user.

MaterialsThe materials used in the tests were

•  Distilled water.•  Poly-N-vinylcaprolactam (PVCap), 0.5 mass% (i.e., 5 g/L of

deionized water).•  Natural gas supplied by Air Products and Chemicals Incorpo-

rated (composition given in Table 1).

Experimental SetupThe new experimental setup, as shown in Fig. 1, was built to simulate various flow-assurance conditions. It comprised a high- pressure, 1500-mm-long, 75-mm-diameter titanium-steel cell that could be placed horizontally, vertically, or at any other angle by use of a pivot system. The total rig volume was approximately 7 L. A movable piston at the base of the cell could be used for controlling the pressure or reducing the volume of the system, if needed. The piston was driven by hydraulic pressure, and its movements could be monitored through a linear variable differential transformer. The piston side of the setup could also be replaced with a stirrer, if nec-essary, to mix the fluid inside the test facilities.

The main body of the cylinder had three separated and indepen-dant cooling jackets designed to establish a temperature gradient along the cylindrical body. In practice, the temperature at the lower part of the cell could be kept outside the HSZ, while the tempera-ture in the upper part could be kept inside the HSZ. The tempera-ture distribution of the cell was controlled by circulating coolant from three cryostats within the jackets surrounding the cell. These cryostats are capable of maintaining the cooling-jacket temperature

An Evaluation of Risk of Hydrate Formation at the Top of a Pipeline

Mahmoud Nazeri, Bahman Tohidi, SPE, and Antonin Chapoy, Heriot-Watt University

Copyright © 2014 Society of Petroleum Engineers

This paper (SPE 160404) was accepted for presentation at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 22–24 October 2012, and revised for publication. Original manuscript received for review 2 January 2013. Revised manuscript received for review 8 November 2013. Paper peer approved 16 December 2013..

68 Oil and Gas Facilities • April 2014 April 2014 • Oil and Gas Facilities 69

to within 0.1 K. To achieve good temperature stability, the jackets were insulated with polystyrene board and the pipes (which connect the cooling jackets to the cryostat) were covered with plastic foam.

Visual observations could be made through the six windows lo-cated on each side of the rig. Ten platinum-resistance temperature probes (with an accuracy of ±0.1°C) were installed to record the temperature distribution along the rig and were connected directly to a computer for data acquisition. All probes were calibrated be-fore starting the experiments. The pressure was measured by means of a strain-gauge pressure transducer mounted directly on the cell and connected to the same data-acquisition unit. This system al-lowed real-time readings and storage of temperatures and pressures throughout the different test runs. There are two ports for fluid in-troduction and withdrawal—one at the top (fixed-end cap) and the other one at the bottom (the upper point of the piston section).

Risk of Hydrate Formation Because of Temperature Gradient in a Pipeline or DeadlegThermodynamic modeling shows that the presence of a tempera-ture gradient (or gradual cooling) could result in water condensa-tion and hydrate formation. The main objective of the first series of tests was to examine the ability of the experimental setup to simu-late temperature gradient and conduct a feasibility test on hydrate formation caused by temperature gradient in a pipeline or deadleg. A deadleg is recognized as an inactive part of the pipeline with no flow or very low flow inside. Deadlegs are commonly connected to the main pipeline, which has hot reservoir fluid flowing inside it. Because there is no flow or low flow inside deadlegs, temperature gradient can occur in them. This temperature gradient can evapo-rate the water from the hot reservoir fluid flowing in the main pipe-line, which can be condensed in the cold top section of the deadleg. Therefore, there is a risk of cooling down into the HSZ and of hy-drate formation in deadlegs.

Before the tests were performed, the equilibrium cell was cleaned and evacuated. First, the rig was loaded with 1.5 L of dis-tilled water (by use of a vacuum or pump). Natural gas was then in-jected until it reached the desired starting pressure at approximately 20°C. The rig was then left to reach stable pressure and checked for leakage. Only five temperature probes were used in the first test: T-01 and T-02 in the top section, T-06 and T-07 in the middle sec-tion, and T-10 in the bottom section (Fig. 1).

Table 2 shows the temperature distribution along the rig, and Fig. 2 illustrates the measured system pressure vs. temperature of T-02 during the test, together with the HSZ for the natural-gas system in the presence of deionized water. At the beginning of the test, the temperature was 20°C at all three sections. Then, to keep the top of the cell inside the HSZ while the other sections were outside of the zone, Set-Point Temp 1 was applied to the temper-ature-control systems of the cooling jackets for each section. The

Fig. 1—The experimental setup.

Temperature probes

Pressure readout

Temperature readout

Top-sectioncooling systemMiddle

section

Coolingjacket

Cylinder

Bottom section

Piston

T-10

T-06T-07

T-02

T-01

Top section

Pressure transducer

Bottom-sectioncoolingsystem

Middle-sectioncoolingsystem

11C 4C20C

Naturalgas

TABLE 1—NATURAL-GAS COMPOSITION (mol%)

Component Feed

Methane 88.36 Ethane 6.13

Propane 1.75 i-Butane 0.20 n-Butane 0.27 i-Pentane 0.06

Carbon dioxide 1.82 Nitrogen 1.33 n-Pentane 0.05 n-Hexane 0.03

Total 100.00

68 Oil and Gas Facilities • April 2014 April 2014 • Oil and Gas Facilities 69

set-point temperature of 4°C, representing the normal temperature of seabeds, was applied to the top section. The set-point tempera-ture of 25°C was applied to the bottom section to have a tempera-ture gradient along the setup, and the middle-section temperature was set to 15°C. After temperature stabilization (Table 2), the min-imum and average temperatures of T-02 at the top of the cell were approximately 9 and 9.4°C, respectively, which was not far enough inside the HSZ to form hydrate. Therefore, the initial set points (Set-Point Temp 1) were changed to Set-Point Temp 2 to achieve lower temperatures at the top of the cell. To achieve this, the set-point temperatures of the middle and bottom sections, which have a significant effect on the top-section temperature, were further re-duced (from 15 to 11°C in the middle section and from 25 to 20°C in the bottom section) to allow further cooling at the top section because the cooling jackets for each section are independent. Also,

Table 2 shows the minimum, maximum, and average temperatures of the temperature probes located in each section of the setup for each set point (Set-Point Temps 1 and 2) to monitor the temperature gradient along the cell.

After setting the Set-Point Temp 2 and further cooling at the top of the cell (Fig. 2), hydrates are formed at 9.3ºC (approximately 8°C subcooling) and 1,274 psig at the top section of the setup. The formed hydrates could be seen in various parts of the section window, as shown in Fig. 3.

In Fig. 2, the pressure of the cell declines gradually because the gas cools down after applying the initial set points (Set-Point Temp 1) to the system. Because no hydrates were formed in the system, Set-Point Temp 2 was applied. The first discontinuity in the operating line in Fig. 2 shows further cooling at T-02. It is clear that the second discontinuity in the operating line (pressure-vs.-temperature graph) is caused by the start of hydrate formation at the top section. The pressure of the system declines more by fur-ther cooling down and more hydrate formation at 7°C (third part of the operating line).

Risk of Hydrate Formation at the Top of a Pipeline Protected With KHIsKHIs are often used for preventing formation of hydrates in pipe-lines carrying gas and gas condensate. However, the main polymers in most KHI formulations are high-molecular-weight components. Because of their low vapor pressure, their concentration in the gas phase is expected to be negligible. Furthermore, KHIs are among the so-called low-dosage hydrate inhibitors and do not have any significant effect on the water-vapor pressure (because of their low concentration). Therefore, any water condensed at the top of a pipeline as a result of temperature gradient or pipeline cooling will not have any KHIs to prevent hydrate formation at the top of the pipeline.

In this series of tests, cooling of an isothermal stratified system was simulated. The main objective was to examine the risk of hy-drate formation at the top of a pipeline where KHIs are the main hy-

TABLE 2—TEMPERATURE DISTRIBUTION ALONG THE RIG IN THE BLANK TEST

Rig Sections Top Section Middle Section Bottom Section

Probe Number T-01 T-02 T-06 T-07 T-10 Set-Point Temp 1 4 4 15 15 25 Minimum Temperature 11.62 8.98 15.65 16.59 25.24 Maximum Temperature 13.22 10.36 16.12 17.28 25.41 Average Temperature 12.05 9.38 15.72 16.89 25.34 Set-Point Temp 2 4 4 11 11 20 Minimum Temperature 8.85 6.64 11.79 12.61 20.78 Maximum Temperature 10.21 7.71 12.26 13.06 21.00 Average Temperature 9.31 6.87 11.93 12.76 20.90

Pre

ssu

re (

P),

psi

g

Temperature (T), °C0 5 10 15 20 25

1500

1250

1000

750

500

250

0

Hydrate Structure IIPhase Boundary

T=17.4°CP=1,274 psig∆T=8.14°C

T=9.3°CP=1,274 psig

Operating lineHydrate lineHydrate-formationpoint

(a) Top (b) Middle (c) Bottom

Fig. 3—Pictures of the hydrates formed in different parts of the top-section window during the blank test.

Fig. 2—Operating line of the blank test. The figure shows sys-tem pressure vs. T-02 with Set-Point Temp 1 and 2. The start of hydrate formation was observed at 9.3°C and 1,274 psig. More hydrate formation is observed at 7°C.

70 Oil and Gas Facilities • April 2014 April 2014 • Oil and Gas Facilities 71

drate-prevention strategy. First, the internal walls of the cell were dried of water. After closing the top flange, a vacuum was applied to the test cell, and then the rig was loaded with 1 L of distilled water mixed with 0.5 mass% PVCap (as the KHI). Natural gas was then injected until the desired pressure (1,000 psig) was reached at approximately 20°C. The rig was left to reach equilibrium, and then the system was cooled down from 20 to 4°C by setting the cooling-jacket temperature at all three sections to a set point of 4°C, sim-ulating shut-in in a subsea pipeline. As can be seen in Fig. 4, the temperature differential between T-02 and T-10 between 975 and 940 psig shows that the top section, which contains the gas phase, can cool down faster than the bottom section, which contains the aqueous phase. The initial set point of 4°C for three sections could not cool down the cell to the target temperature of 4°C. Therefore, the set points were changed to 1°C in all three sections for further cooling. The discontinuity in the operating lines of T-02 and T-10 can show the change in the set-point temperatures.

Hydrate-phase boundaries for Natural-Gas Structures I and II (s-I and s-II) were predicted by use of the in-house thermody-namics model, HydraFLASH (Chapoy et al. 2008; Haghighi et

al. 2009a, b, c) and are shown in Fig. 4, together with the mea-sured pressure and temperature during the test. As the graph in Fig. 4 shows, hydrates were formed at approximately 5°C and 910 psig (i.e., 10.5°C subcooling). Hydrates were also observed at the bottom of the middle section, approximately 5 cm above the free-water level, as shown in Fig. 5. The large quantities of hydrates just above the aqueous phase are potentially caused by the high water content of the gas phase at locations near the gas/water interface. It is believed that the gas loses much of its water content because of hydrate formation; hence, there are fewer hydrates at the top of the cell (please note that the cell is at near-isothermal conditions).

After this test, the water-phase temperature was increased to 20°C (bottom of the rig), while the top-section and middle- section temperatures were kept constant to simulate the condition in a deadleg. In this case, the aqueous phase was outside the hydrate-phase boundary, while the gas phase was still inside the HSZ. The objective was to examine the rate of increase in the amount of hy-drates. The hydrate volume increased during the 20-hour-test pe-riod, demonstrating that hydrates could grow in a gas phase with water vapor coming from a hotter aqueous phase. However, an in-crease in the thickness of the hydrate layer could reduce the heat-transfer rate because hydrates could act as an insulator. This could result in a reduction or complete stoppage of hydrate deposition in a deadleg, which requires further investigation. Finally, the temper-atures of the three sections of the test facilities were set to the initial temperature of 20°C, dissociating all the hydrates in preparation for the next experiments.

Anderson et al. (2011) and Glénat et al. (2011) have reported that KHIs have a complete-inhibition region (CIR) in which they can provide almost indefinite protection (similar to thermody-namic inhibitors); hence, KHIs could be used in shut-in condi-tions. On the other hand, there is a general view that KHIs prevent hydrate nucleation and if hydrate crystals come into contact with an aqueous system containing KHIs (which is already inside the HSZ), the KHIs can no longer prevent hydrate formation in the aqueous phase. A test was planned to simulate hydrate formation in the gas phase caused by cooling (or temperature gradient) in a system containing KHIs, but within the KHI’s CIR. To simulate shut-in followed by startup conditions, the temperatures at the top and bottom of the cell were set at 4 and 10°C, respectively. Some hydrates were formed in the gas phase (Fig. 6) after 24 hours with no hydrates observed in the aqueous phase, despite it being inside the HSZ (Fig. 7). This was expected because the system was inside the CIR, and the KHIs present in the aqueous phase prevented hy-drate formation. The system was then left under hydrate-forming

Fig. 4—HSZs for s-I and s-II hydrates, together with measured pressure and temperature conditions during the test in the pres-ence of KHIs. The figure shows the cell pressure vs. the tem-peratures at two sections of the cell (i.e., top and bottom). The temperatures at the two sections (T-02 and T-10) are very close. The sharp drop in the system pressure at 5°C is caused by hy-drate formation in the gas phase because the liquid phase is protected by the presence of KHIs.

Fig. 5—Pictures of hydrates formed at the bottom of the middle section, just above the free-water phase. In this test, hydrate forma-tion in the aqueous phase was prevented by 0.5 mass% of KHI.

Pre

ssu

re, p

sig

Temperature, °C0 5 10 15 20 25 30

1050

1000

950

900

850

800

∆T=7°C∆T=3.5°C

Hydrate formation, T-02Hydrate dissociation, T-02Hydration formation, T-10Natural-gas hydrate line, s-IINatural-gas hydrate line, s-I

70 Oil and Gas Facilities • April 2014 April 2014 • Oil and Gas Facilities 71

conditions for a week to monitor the rate of hydrate growth (Fig. 7). As shown in Fig. 7, the system temperatures at the top and bottom of the cell are approximately 5 and 10°C, respectively. No signifi-cant increase in the amount of hydrates in the gas phase was ob-served under these conditions. Again, this was somewhat expected because there was no significant temperature gradient between the top and the bottom of the cell; hence, there was limited driving force for water evaporation considering the low vapor pressure of water at 9°C.

With the hydrates in the gas phase and the whole system inside the HSZ, the setup orientation was changed from a vertical to a hor-izontal position three times to simulate the aqueous phase coming into contact with the hydrates present in the gas phase (e.g., slug flow in a pipeline). Each time, the system was left for 5 minutes in the horizontal position. The water temperature, with dissolved KHIs, was approximately 9°C (i.e., approximately 6°C sub-cooling), which is inside the CIR of the KHI. As shown in Fig. 8, the hydrates at the top of the cell began dissociation after contact with the aqueous phase containing KHIs. This is the opposite of the

general understanding that the presence of hydrate crystals will un-dermine the ability of the KHIs to prevent hydrate formation. In-stead, dissociation of hydrates was observed. It is believed that the hydrates that formed in the gas phase, and in the absence of KHIs, will partially dissociate to satisfy new equilibrium conditions, but the KHIs will prevent any hydrate growth in certain directions if the system is inside the CIR. The initial results in this work indi-cate that if hydrates are formed in the gas phase, they can dissociate if they come into contact with a slug of aqueous phase containing KHIs, assuming the entire system is within the CIR of that specific KHI. Fig. 8 shows the hydrate particles (partly shown in Fig. 6) after coming into contact with water containing KHIs.

ConclusionsA new experimental setup was designed and constructed at the Centre for Gas Hydrate Research, Heriot-Watt University, for sim-ulating various production scenarios, such as risk of hydrate for-mation at the top of pipelines and/or deadlegs. Some preliminary investigation was conducted to examine hydrate formation in a gas phase at the top of a pipeline (when stratified flow is the domi-nating flow regime) and/or deadlegs. The results of the new work (to date) confirm the following:

1. Water condensation at the top of a pipeline associated with temperature gradient (and/or system cooling) could result in hydrate formation in the gas phase, if the conditions in the gas phase are inside the HSZ.

2. Hydrates formed in the gas phase can grow if there is suf-ficient temperature gradient between the aqueous phase and the gas phase.

3. In KHI-inhibited systems, hydrates could form in the gas phase because of water condensation as a result of cool down and/or temperature gradient if the system is inside the HSZ, despite hydrates being prevented in the aqueous phase by KHIs.

4. Hydrates formed in the gas phase could dissociate as a re-sult of contact with the aqueous phase containing KHIs if the system is inside the CIR of the KHI.

The work presented here is a preliminary investigation by use of a new experimental setup. Further investigation is required to examine the effect of various other parameters, including tempera-

Pre

ssu

re, p

sig

Temperature, °C0 5 10 15 20 25 30 35

1000

950

900

850

800

750

700

650

600

550

500

Hydrate formation, T-02Hydration formation, T-10Natural-gas hydrate line, s-IINatural-gas hydrate line, s-IDissociation curve, T-02

Fig. 6—Pictures of the hydrates formed in the third test in the gas phase. The hydrates formed in the gas phase when both gas and aqueous phases were inside the HSZ while the aque-ous phase was protected with KHIs. As expected, no hydrates were observed in the KHI-protected aqueous phase; however, hydrates can start to form in the gas phase.

Fig. 7—s-I and s-II HSZ for the natural gas in the presence of KHIs together with measured pressure and temperature condi-tions at the top and bottom of the cell. As shown in the figure, the conditions at the top and bottom of the cell are inside the HSZ; however, no hydrates were formed at the bottom of the cell because of the presence of KHIs (the observed pressure drop is caused by hydrate formation at the top of the cell). Hydrates are formed at the top of the cell because there are no KHIs in the gas phase.

Fig. 8—Hydrate particles formed in the gas phase in contact with water containing KHIs. The hydrates began dissociation after coming into contact with the aqueous phase containing KHIs.

72 Oil and Gas Facilities • April 2014 April 2014 • Oil and Gas Facilities PB

ture gradient, presence of a liquid-hydrocarbon layer, turbulence, gas bubbling through the liquid phase (e.g., holdup), and various other scenarios, during shutdowns and startups and the associ-ated upscaling.

ReferencesAnderson, R., Mozaffar, H., and Tohidi, B. 2011. Development of a Crystal

Growth Inhibition Based Method for the Evaluation of Kinetic Hy-drate Inhibitors. Presented at the 7th International Conference on Gas Hydrates, Edinburgh, Scotland, UK, 17–21 July.

Chapoy, A., Anderson, R., Haghighi, H., Edwards, T., and Tohidi, B. 2008. Can n-propanol Form Hydrate? Ind. Eng. Chem. Res. 47 (5): 1689–1694. http://dx.doi.org/10.1021/ir071019e.

Glénat, P., Anderson, R., Mozaffar, H., and Tohidi, B. 2011. Application of a New Crystal Growth Inhibition Based KHI Evaluation Method to Commercial Formulation Assessment. Presented at the 7th Inter-national Conference on Gas Hydrates, Edinburgh, Scotland, UK, 17–21 July.

Haghighi, H., Chapoy, A., and Tohidi, B. 2009a. Methane and Water Phase Equilibria in the Presence of Single and Mixed Electrolyte Solu-tions Using the Cubic-Plus-Association Equation of State. Oil & Gas Science and Technology-Rev. IFP 64 (2): 141–154. http://dx.doi.org/10.2516/ogst:2008043.

Haghighi, H., Chapoy, A., Burgess, R., and Tohidi, B. 2009b. Experimental and thermodynamic modelling of systems containing water and eth-ylene glycol: Application to flow assurance and gas processing. Fluid Phase Equilibria 276 (1): 24–30. http://dx.doi.org/10.1016/ j.fluid.2008.10.006.

Haghighi, H., Chapoy, A., Burgess, R., et al. 2009c. Phase equilibria for pe-troleum reservoir fluids containing water and aqueous methanol so-lutions: Experimental measurements and modelling using the CPA equation of state. Fluid Phase Equilibria 278 (1–2): 109–116. http://dx.doi.org/10.1016/j.fluid.2009.01.009.

Kinnari, K., Labes-Carrier, C., Lunde, K., et al. 2008. Hydrate Plug Forma-tion Prediction Tool—An Increasing Need for Flow Assurance in the Oil Industry. Oral presentation given at the 6th International Confer-ence on Gas Hydrates (ICGH 2008), Vancouver, British Columbia, Canada, 6–10 July.

Lunde, K., Kinnari, K.J., and Labes-Carrier, C. 2012. Method for protecting hydrocarbon conduits. US Patent Application No. 20120090686: PCT Application No. PCT/GB2008/003219.

Mahmoud Nazeri is a PhD-degree candidate in the Hydrate, Flow Assur-ance and Phase Equilibria Research Group at the Institute of Petroleum Engineering at Heriot-Watt University. Currently, he investigates the im-pact of impurities on thermophysical properties of CO2-rich systems, and also works on flow-assurance projects for Hydrafact Limited on a part-time basis. Nazeri has more than 8 years of work experience in the oil and gas industry as a process and multiphase-flow-assurance engi-neer. He holds a BSc degree in chemical engineering from the Univer-sity of Tehran, Iran.

Bahman Tohidi is a professor at Heriot-Watt University, where he serves as Director of the Centre for Gas Hydrate Research and Deputy Head of the Institute of Petroleum Engineering, and where he leads the Hydrate, Flow Assurance and Phase Equilibria Research Group at the Institute of Petroleum Engineering. He is currently working on several projects on various aspects of gas hydrates and flow assurance, phase behavior and properties of reservoir fluids, and CO2-rich systems. Tohidi serves as a consultant to major oil and service companies, and is Managing Di-rector of Hydrafact Limited, a Heriot-Watt spin-out company, with flow assurance and pressure/volume/temperature (PVT) as its main area of activity. He has published more than 200 papers and holds several patents, mainly in gas hydrates and PVT. Tohidi holds a BSc degree in chemical engineering and a PhD degree in petroleum engineering. He was an SPE Distinguished Lecturer in 2004–2005, and has been a member of SPE since 1992.

Antonin Chapoy is a senior research fellow at Heriot-Watt University, having joined the Centre for Gas Hydrate Research at Heriot-Watt Uni-versity as a research associate. He has more than 10 years of research experience in gas-hydrate and hydrocarbon phase behavior and has managed a wide range of projects, mostly sponsored by industry. Chapoy has authored or coauthored more than 100 refereed-journal and confer-ence publications, primarily concerning gas hydrates, flow assurance, and water/hydrocarbon phase behavior. He holds a DEA (MSc) degree in chemical engineering from the Université d’Aix-Marseille, Marseille, France; an MSc degree in energy engineering from the Institut Universi-taire des Systémes Thermiques et Industriels, Marseille; and a PhD de-gree in chemical engineering from the Paris School of Mines.