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An Insight to InhibitorsGas hydrates may form in any location where a free gas, water, the appropriate temperature,pressure and time exists in space, in the atmospheres of the planets, inside the planets and in thetechnical systems of production, transportation and processing of gases. Hydrates may form andshut the gas flow rate partially or completely in the well bottom zone of a layer; in a well bore – in afountain tubing column, in annular space, in well top pipes or in near well top equipment, in asystem of field pipelines and installations, in transport gas pipelines and product pipelines and inunderground systems of gas storage. The cost to the petroleum industry to inhibit the formation ofgas hydrates is estimated to represent 5% to 8% of the total product plant cost. This paper discussesthe various inhibitors, advantages, disadvantages, limitations and estimation.

TechnologyTechnology

Gas hydrates are solid crystalline compounds,which have a structure wherein guest mole-cules are entrapped in a cage like frameworkof the host molecules without forming a

chemical bond. It is a result of the hydrogen bond thatwater can form hydrates. The hydrogen bond causes thewater molecules to align in regular orientations. Thepresence of certain compounds causes the alignedmolecules to stabilize, and a solid mixture precipitates.The water molecules are referred to as the host mol-ecules, and the other compounds, which stabilize thecrystal, are called the guest molecules. The hydratecrystals have complex, three dimensional structures inwhich the water molecules form a cage and the guestmolecules are entrapped in the cages. The stabilizationresulting from guest molecule is postulated to be causedby Vander Waals forces, which is the attraction be-tween molecules that is not a result of electrostaticattraction. Another interesting thing about gas hy-drates is that no bonding exits between the guest andhost molecules. The guest molecules are free torotate inside the cages built up from the host mol-ecules. This rotation has been measured byspectroscopic means. No hydrate without guest mol-ecules has been found in nature. Thus Clathrates(Inclusion compounds) are stabilized by the weakattractive interactions between guest and water mol-ecules. However, the guest species have some re-strictions on its size. This arises from the fact that

there are a limited no. of cage types which encapsu-late guest molecule without deviation of the hydro-gen bond lengths and angle from ideal ones. All ofthe cages are not necessarily depend on the tem-perature and the pressure of the guest compound inequilibrium with clathrate hydrate.

To avoid the undesirable formation of gas hydratesin flow lines / risers/pipelines, inhibitor injection isunavoidable.

Chemical InhibitionThere are three types of inhibition. They are Thermo-

dynamic, Kinetic & Anti Agglomerants.

Thermodynamic hydrate inhibitors (THI)This inhibitor is added to a two component system

(water + gas) which changes the energy of intermo-lecular interaction and changes thermodynamic equi-librium between molecules of water and gas.

MechanismThese chemicals work by altering the chemical po-

tential of the aqueous phase such that the equilibriumdissociation curve is displaced to lower temperatureand higher pressure. Electrolytic solutions are used asthermodynamic inhibitors beside alcohols. Actuallythe chemical potential of water molecules decreases.So, the equilibrium in the reaction of hydrate forma-tion moves to the left.

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Water + Gas ↔ Hydrateµwater + µgas ↔ µhydrate

Where µ is chemical potential

The chemical potential of a constituent in a mixtureis the increase in the free energy which takes place atconstant temperature and pressure when one mole ofthat constituent is added to the system, keeping theamounts of all other constituents’ constant i.e. onemole of the constituents is added to such a largequantity of the system that is composition remainsalmost unchanged. The chemical potential of a con-stituent in a mixture is its contribution per mole to thetotal free energy of the system of a constant composi-tion at constant temperature and pressure. It is anintensive property because it refers to one mole of thesubstance (µ). Thermodynamic inhibitors (Typicallymethanol or mono ethylene glycol) are injected intoprocessing lines as a means of hydrate control bybreaking hydrogen bonds and by competing for avail-able water molecules. The effective use of inhibitor ispossible only when a pipeline operation is thoroughlyprepared and controlled. Otherwise the injection ofinhibitors will not only be useless, but could alsopromote plug formation. The risk in using thermody-namic inhibitors includes:

• Under dosing, particularly due to not knowingwater production rates.

• Inhibitor not going where intended (Operator erroror equipment failure).

• Environmental concerns, particularly with metha-nol discharge limits.

• Ensuring remote location supply.• Ensuring chemical/ material compatibility; and• Safety considerations in handling methanol top-

sides.Application: Multiphase, gas condensate and

crude oil.Advantages: More effective, well understand, predict-

able and proven track record.Disadvantages: They are added at relatively high

concentrations (10-60 wt% in the aqueous phase),Toxic/ hazardous, environmentally harmful and

volatile losses to vapor (e.g. Methanol, glycols)Alcohols: Methanol and Ethanol are the hydroxyl

group alcohol inhibitors, which when used hydro-gen bond with the water molecules. Hydrate inhibi-tion abilities are less for larger alcohols i.e. Methanol> Ethanol > Iso - propanol.

Methanol: Methanol is widely used as hydrate inhibi-tor. It has some disadvantages. Let us consider the LPGpipelines. LPG is made up largely of propane and mixedbutanes. The methanol added as an inhibitor, formspropane + methanol and n-butane + methanolazeotropes, because of this methanol will appear inunacceptable levels. Gas contaminated with MeOH isunacceptable in the cryogenic “Cold Box” part of a LNGplant. MeOH has the freezing point well above thetemperature in LNG plant. For this reason the use ofMeOH is generally avoided for LNG based gas process-ing facilities or an additional pre treatment systemremoving the MeOH from gas is necessary. In pipelines,generally we add corrosion inhibitors. Some corrosioninhibitors are alcohol-based. The methanol added as ahydrate preventer, dissolved the corrosion inhibitorwhich leads to some unexpected corrosion problems.Under sour conditions the presence of methanol canincrease risk of sulfide stress cracking and stress –oriented hydrogen induced cracking. Methanol for in-hibitor is usually stored on site in tanks that are open tothe atmosphere. This allows some air to dissolve in tomethanol. Typically, the amount of dissolved oxygen issmall, over the long term this could cause problems.(The solubility of oxygen in seawater at 200C is 7.2 ppmas compared to 79 ppm in alcohol.) In sour system, alarge amount of methanol has the potential to carry alarge amount of dissolved Oxygen. The oxygen canreacts with H2S produces elemental sulphur whichincreases the risk of under deposit corrosion.

In sweet system, oxygen diffuses to the metal sur-face and increases the corrosion rate. Oxygen intro-duced into a sour system lead to change in compositionand morphology of the iron sulfide layer leading tothe formation of FeS scale that is less protective whichincreases the risk of localized corrosion. Methanol isa volatile substance; we have to pay attention onvapor loss. In practical terms, this means that moreinhibitor must be injected than the amount requiredfor mitigating the hydrate formation theoretically.Depending on operating conditions, the solubilityloss of methanol into sales gas can be very high,typically 1lb of methanol / MMSCF for every %methanol in water phase. Losses to liquid hydrocar-bon are usually less than 1 – 2 % of hydrocarbonvolume. As a general rule, the anti microbial activityof alcohols increases with molecular weight andchain length to about C10, while the methanol isgenerally considered as poor anti-microbial agent,

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Ethanol exerts maximum activity at 60 to 90 Vol.%.The methanol concentration of water discharged (ef-fluent) is limited to 1000 ppm Max.(North Sea). Safetyissues (poison, volatility) and inventory managementare also main concerns in the handling of the metha-nol. Methanol is seldom used to dissociate a hydrateplug unless the injection point is vertically above ahydrate plug (as in riser or a well); Methanol isnormally used for flow line plugs. Methanol injectedin to the gas pipelines can be recovered in gasprocessing with turbo expander plant. Methanol isfully miscible with water, while the solubility ofmethanol in hydrocarbons is very small. Therefore,water can be used to extract methanol from thehydrocarbon condensate efficiently. Since water isthe solvent, this extraction process is called waterwash. More than 96% of methanol injected can berecovered, if good engineering judgment and experi-ence are applied. At 390F and pressure greater than1000 Psia, the methanol lost to the vapour phase is 1lbm Methanol / MMSCF for every weight % in the free– water phase. Methanol concentration dissolved incondensate is 0.5 weight %. Methanol loss costs canbe substantial when the total fraction of either thevapour or the oil / condensate phase is very largerelative to the water phase.

Glycols: These have more hydrogen bonding oppor-tunity with water through one more hydroxyl groupthan alcohols. Glycols generally have higher molecu-lar weights, which inhibit volatility; the commonlyused glycols are ethylene glycol, tri-ethylene glycol,propylene glycol, and poly-alkylene glycol. Alcoholsand glycols, when dissolved in aqueous solution formhydrogen bond with the water molecules and make itdifficult for the water molecules to participate in thehydrate formation. The higher the molecular weightsof the glycols cause them to remain in the liquid phaseso they are more recoverable than methanol. Due tovaporization losses of glycols, Toensend and Riderecommend that ethylene glycol be used where systemtemperature are lower than 255K and that di-ethyleneglycol be used above temperature. It has been learnedthat minimizing the oxygen level within the closedloop mono-ethylene glycol system is important toavoid transformation of iron carbonate to iron oxide,avoid an increasing corrosion rate and avoid possibledegradation of the mono-ethylene glycol. Hence avoid-ing the oxygen ingress to the system is very important(use Oxygen Scavenger).

Toensend and Ride suggest that some other factorsshould be considered for the use of glycol injectionsystem.

• The presence of salt is serious obstacle due tofouling and corrosion.

• The PH of the solutions should be controlled at 7 toavoid corrosion.

• The glycol atomization. (at low temperature)• Glycol-water solution will freeze, if they are too

dilute or too concentrated• Nelson indicates that at 233 K the viscosity of 80

wt% of methanol was only three times that of waterat ambient conditions. While the viscosity of ethyl-ene glycol was 480 times that value for the samecondition. In order to ensure flow through valves.Heat exchangers we have to maintain the viscositybetween 100-150 centipoise.

• Dew point reductions of 35-40 0C without gasstripping and 50-60 0C with it are obtainable. Atcontactor temperature above 60 0C, Tetra EthyleneGlycol should be considered.

• At 390F and pressure greater than 1000 Psia, themaximum amount of MEG lost to the gas is 0.02lbm/mmscf.

• The mole fraction of MEG in a liquid hydrocar-bon at 390F is 0.03% of water phase mole frac-tion of MEG.

• The concentration of inhibiting MEG in the waterphase can be determined from methanol concen-tration with a simple correlation of inhibitors.Wt.% MEG = -1.209+2.34(wt.% MeOH)-0.052(wt.% MeOH) 2+0.0008(Wt% MeOH) 3 .

• MEG injection is used when the required MeOHinjection rate exceeds 30 gal / hr for onshore gaslines.

• The following formula was used to calculate theamount of MEG required to inhibit the hydrate inSakhalin - 2.MEG Rate (m3/hr) = 1 + 4.2 * 10-3* Gas Rate (Ksm3/hr) + 2.4 * 10 -3 * Condensate rate (M3/hr).

Advantages: Low capital & operating costs, reliable,Recoverable (Regeneration & Reclamation), very flex-ible and low weight.

Disadvantages: Heat required, may foam with Oil/Condensate and limited dew point reduction.

Low Dose Hydrate Inhibitors (LDHI): KineticInhibitors

Kinetic inhibitors does not shift the hydrate equilib-

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rium conditions; rather, they decrease the rate atwhich hydrate form, preventing plugs for a periodlonger than the free water residence time in a gas line.They bond with the hydrate surface, delaying crystalgrowth for a period of time that is longer than theresidence time of free water in the system. Kineticinhibitors are added at low concentrations (less than1 wt% in the aqueous phase).

Mechanism1. It adsorbs on the surface of hydrate micro

crystals and dispersed droplets of water in theflow of a fluid. It sharply change the diffusive-sorptional exchange at the inhibitor water in-terface; Which decrease the rate of microcrystals growth, their coagulation, sedimenta-tion and adhesive parameters, thus preventingthe formation of large gas hydrate plugs inwells/ pipelines.

2. Thus kinetic inhibitors do not prevents the hydrateformation, but shifts the time and space the forma-tion of large hydrate plugs.

3. It must be very soluble in water, not hydrolyzeto insoluble compounds, and adsorb well on apolar surface of hydrate micro crystals formingand external surface preventing the associa-tion of hydrate crystals. Fatty acids, mixture offatty alcohols and amines etc can be used askinetic inhibitors.e.g., Poly-N-Vinyl Amides,Poly-N-Vinyl-N-Methyllaptamide and Poly-N-Vinylpyrolidone (PVP)

The one of the paper by Fu et al. describes thesuccessful application of the copolymer ofvinylmethylacetamide and vinylcaprolactam tofour field locations. In all cases the KHI provided aworkable and cost-effective alternative to tradi-tional inhibitors. However, all systems were gasbased and none of the cases were representative ofblack oil systems. NOTZ et al. report on successfulfield trials of poly vinyl pyrolidone (PVP) in gas wellsand pipelines in Wyoming. They support that PVPwas used as a replacement for methanol givingbeneficial reductions in chemical costs and im-proved hydrate control.

Applications: Multiphase, gas and condensateAdvantages: Low cost, Low volumes (21 wt %), envi-

ronment friendly, non toxic and tested in gas systems,Performance Not influenced by temperature.

Disadvantages: Limited sub-cooling (<100C) i.e.,

typically only guaranteed for less than 100C, timedependency, it may interact with other chemicalinhibitors (corrosion inhibitors), testing programsare required prior to implementation, there are noestablished models for predicting the effectivenessand limited experiences in oil systems.

AntiagglomerantsThese are surface active chemicals (surfactants)

which do not attempt to prevent hydrate crystals fromforming but rather prevent them from agglomeratingto form hydrate plugs.

MechanismThe antiagglomerant works by emulsifying hydrates

in the hydrocarbon liquid. Hydrates are carried as aNon – Agglomerated slurry, without viscosity in-crease up to 50 % water cut. Thus they do not displaythe same pressure temperature limitations as kinetichydrate inhibitors. However, antiagglomerants knownto date only work in systems with a continuoushydrocarbon liquid phase and then effectiveness isdependent on the type of oil/ condensate, the salinityof the formation water and the water cut. In addition,the operation of the pipeline can also important sincedispersions of small hydrate crystals will be favoredby higher velocities where as at low flow rates crystalsmay settle out and agglomerate that the oil hydratesdensity difference is sufficient. This is analogous tothe behavior of water oil dispersions in wet crude oilpipelines. The antiagglomerants provide protectionup to 40:60 water oil ratios.

Application: Multiphase, gas condensate andcrude oil.

Advantages: Low volumes (21 wt %), environmentfriendly, non toxic and It does not have the sub coolinglimitations.

Disadvantages:There is uncertainty about the ef-fectiveness of antiagglomerants compared to kinetichydrate inhibitors and it is postulated that agglom-eration may still proceed. One major limitation ofantiagglomerants compared to kinetic hydrate in-hibitors and thermodynamic hydrate inhibitors isthat they are limited to lower water cuts due to therequirement for a continuous hydrocarbon liquidphase, Limited experience, No predictive models,System specific.

NH3: Ammonia is more than twice as effective asmethanol on a weight basis, NH3 seldom used due to the

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reaction of NH3 with CO2 in the gas to form solid plugsof ammonium carbonate, bi carbonate, and carbonatewhich are more difficult to remove than hydrate plugs.The handling of ammonia is safety consideration. Atextreme conditions, NH3 can be used as inhibitor.

Salts: Commonly used salts are Nacl, Kcl, CaCl2

and Sodium salts in the solution and interact with thedipoles of water molecules and cause clustering.This clustering also causes a decrease in the solubil-ity of potential hydrate guest molecules in the water.These combine to require substantially more subcooling to cause hydrates to form.

Drilling Fluid InhibitionThe desirable characteristics of hydrate inhibitor for

drilling fluids are as follows. The lowest density possi-ble with maximum hydrate suppression. The drillingfluids play a vital role in the hydrate suppression. Thedesirable properties of the drilling fluids are:

• The relative density of the drilling fluid musthave an appropriate change range. The drillingfluid can supply a definite pressure to counter-act the stratums and prevent hydrates aroundthe borehole from decomposing to keep theborehole well stable. For practical situation ofhydrate sediment, it’s optimum density shouldbe in the range of 1.05 – 1.2, according to thesafe density window of drilling fluid.

• The drilling fluid should be able to effectivelyinhibit shale hydration and gas hydrate aggre-gation in the drilling pipe and blowout preventer.

• The drilling fluid should have good rheologicalproperties and stability at low temperatures.

• The drilling fluid should prevent calcium- andmagnesium – ion pollution. Normally, the con-centration of calcium and magnesium ions in theocean is about 0.40 g/kg and 1.28 g/kg respec-tively. Though these percentages are less, theycan greatly influence the performance of thedrilling fluid.

• The drilling fluid must have sufficient lubricationand low filtration.

• While drilling in gas – hydrate bearing forma-tions, it is suggested that the drilling fluid have ahigh circulation speed to inhibit gas – hydratedecomposition and reformation. Because theheat produced by aiguilles cutting stratums canbe rapidly dissipated by the drilling fluid, thedrilling fluid can be renovated rapidly. This

process is helpful for cooling the drilling fluid bycold water around drill pipe in deep seas, whichcan help control of the hydrates around theborehole and wellbore stability.

• Compatibility with most common drilling fluid com-ponents

• Compatibility with most salts to balance hydratesuppression and fluid density

EXXON (1988) used salt at saturation limit range of150-170 mg/lit to prevent hydrate formation. SHELLused 20 wt % Nacl & partially hydrolyzed poly acrylamide muds for drilling depths between 2000-7500feets (Gulf of Mexico). HALF proposed, 14 lbm/galmud is to be used to protect against hydrate forma-tion in 7500 ft is environmentally safe and non-flammable. In addition 20 wt % Nacl & 30 wt %glycol will protect against hydrate formation up to5000ft. In a recent survey of drilling literature, themost common deepwater drilling fluids are 20 to 30wt.% NaCl / PHPA (Partially Hydrolyzed Polyacry-lamide) systems that have been used successfully atdepths up to 7500 ft. High – KCl (<24 wt.%) drillingfluids are the second most frequently used.

While KCl gives very strong shale stability, it is amuch weaker hydrate inhibitor than NaCl. ThePHPA – NaCl system can function effectively withlimited amount of KCl (3 wt%) or without KCl at all.Such particular formulation with 20wt% NaCl forhydrate inhibition, the 10 lb/gal fluid could providehydrate inhibition depths up to 1650ft (Most com-mon in GOM). There is experience with 18 CaCl2

drilling fluids in the field at concentration of<32wt.%, these drilling fluids provide fairly strongshale inhibition and are capable of excellent hy-drate inhibition but are difficult to formulate as gooddrilling fluid because of the interaction of Calciumions (Ca2+ ) with clay and water soluble polymers. A50% solution of Potassium Formate (KCOOH) has afreezing point of around -600C and has high density.This is the reason behind the use of KCOOH (asadditives) in drilling fluids.

Regeneration and recovery is also simple in prin-ciple. It can be used as an inhibitor also. Glyceroland Poly glycerol have acceptable physical andenvironmental properties, but their high densityprevents their use in the low density formulas re-quired by deep water formation-fracture gradients.Sodium Chloride (NaCl) is the cheapest and mosteffective additive for thermodynamic hydrate inhi-

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bition in water – based muds. Often top – holesections must be drilled with mud weights in the 9 to10 lb/gal range, thus limiting the amount of salt(NaCl) that can be added to the drilling fluid toprovide hydrate inhibition. Traditionally, high lev-els of glycol, at times in excess of 20 wt% are usedto provide acceptable levels of hydrate inhibition. Athigh concentrations, calcium chloride is also veryeffective hydrate inhibitor, but environmental andnumerous technical constraints limit the use of cal-cium chloride in water – based mud. The hydrateformation in fresh water based mud depends on theconcentration of salt. Only salt will behave as anti-freeze for hydrate formation among the other con-tents of fresh water based mud. Most effective saltsin terms of affectivity and degree of sub cooling areCaCl2 , NaBr and NaCl.

Howard indicated how to calculate the effect of saltson the hydrate formation temperature by freezing pointdepression data for the salts.

Teq,s= Teq- 0.8 * ∆Tfreezing

Where, Teq,s= Hydrate Equilibrium Temperature inbrine 0C

Teq= Hydrate Equilibrium Temperature in brine 0C∆Tfreezing = Freezing point depression by brine 0C

By using the above equation it is possible to estimatethe salt concentration in drilling fluids.

A performance report “Nigeria: Glydrill PromotesTrouble – free Drilling” includes information aboutdeepwater well offshore Nigeria was successfully com-pleted by using a Potassium Chloride, Glydrill MCsystem. They used 4 to 5% Glydrill MC to achievechemical well bore stability. The KCl+Glydrill MCfluid provided a cost effective system for drilling allhole sections.

Another performance report “Denmark: GlydrillSystem Successfully Drills 7,827 ft Section” containinformation about how the drilling fluid performedexceptionally throughout the well, giving high lev-els of lubricity and well bore stability. The system,utilizing a high potassium content, was designed tostabilize the long section of reactive and lubricity.Also this system had lower fluid costs by com-pletely recycling which affected in reducing over-all fluid costs. Also it was environmentallyacceptable. The Glydrill water – base system wasapproved for discharge, thus reducing overall mud

costs by eliminating the expense of slurrificationand injection equipment.

This system did not affect on cementing operationand also the cement contamination did not affect theperformance of the system. The contamination ofGlydrill MC and Glids HD provided low coefficientof friction resulting in minimum torque and dragthroughout the system. The addition of Glydrill MCand 1.5% Glide HS provided well bore stability.

Glydrill MC polyglycol of M-I L.L.C is a mediumcloud point (the temperature, where polyglycoladditives change from being soluble which is atlower temperature to being insoluble at highertemperature) additive designed for medium to highsalinity poly glycol system. The physical appear-ance is straw yellow to opaque, brown liquid. It has1.012 specific gravity and solubility in water isvariable. Cloud point of this liquid is above 1500 Fin situation of 3% of Glydrill MC Poly glycol and10% concentration by volume of NaCl. Antiaggloraments, dispersant additives or kinetic addi-tives are added with thermo-dynamic inhibitors toprevent/ slow hydrate formation.

A few methods are available to predict the hydrateformation in the drilling fluids such as Mud activitymethod, Drilling fluid composition method & Resis-tivity and Density method. Selection of method isbased on the past experience.

Evaluation of InhibitorsThe relative inhibition power (RIP) is defined as,RIP = (End point with inhibitor – End point without

inhibitor)/ (End point without inhibitor)

Inhibitor EstimationStep 1: Calculate hydrate formation conditions. (Use

gas gravity chart or empirical equations orsimulation)

Step 2: Calculate the weight percent MeOH /MEGrequired in the free water phase. (useHammerschmidt Eq.)

Step 3: Calculate the mass of condensed water. (Inthe absence of water analysis, use waterformation curves)

Step 4: Calculate mass of produced water flowing intothe line.

Step 5: Find the total mass of water. (Add Condensed& Produced water)

Step 6: Calculate MeOH / MEG in total water phase.

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Step 7: Calculate MeOH / MEG lost in gas phase.Step 8: Calculate MeOH / MEG lost in condensate.Step 9: Find total MeOH / MEG required (Total water /

gas / condensate phases)Step10: Add design margin.

ConclusionThere is no single guideline to select inhibitor

which inhibits hydrate formation. The selection isbased on the GOR, Water cut, operating conditions,environmental conditions, physical & chemical prop-erties of the inhibitor, interaction with other injec-tion chemicals such as corrosion inhibitor, stability,solubility, environmental regulations, availability,safety & cost. However this paper briefs about vari-ous inhibitors and its applicability & limitation. Thispaper also outlined the estimation procedures. Ki-netic & Anti - Agglomerants should be used based onthe previous experience and proven track record.While using the salts as inhibitors, solubility (pre-cipitate formation) & scale formation problems hasto addressed additionally.

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This publication thanks Mr.B.Chandragupthan, Senior Engi-neer (Process Technology), SaipemIndia Projects Ltd for providingthis article. Mr. Chandragupthan

holds a Bachelor of Technology (Chemical En-gineering) from University of Madras and aMaster of Technology (Refining and Petrochemi-cal Engineering) from University of Petroleumand Energy Studies, Dehradun, India. Hehaspreviously worked as a Deputy Manager (Proc-ess Dept.) with PL Engineering Ltd., Gurgaon,India. He has more than six years experiencein Plant Design, Operations and Maintenance.He has published / presented more than twentypapers on “Gas Hydrates”, “Flow Assurance”and “Energy Economy”.