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AbstractThe state of the art of three hydrate applications in petroleumengineering is presented in order of decreasing importance:(1) flow assurance, (2) energy resource, and (3) climatechange. In flow assurance, there is a hydrate-plug-preventionshift under way: from avoidance to management of hydrate

formation. In addition to avoiding the region of hydrate sta-bility by injecting thermodynamic inhibitors, time-dependentstudies enable flow-assurance engineers to better address suchconcerns as flowline restarts, cold (stabilized) flow, low-dosagehydrate inhibitors, and plug remediation. These applicationsare related to conceptual ideas of hydrate-plug formation inoil and condensate systems. The second area, energy resourc-es, is marked by a transition to an extended production test inthe permafrost, and to characterizing resources and econom-ics in the marine environment. The third area, climate changecaused by hydrates, is an area of current research. Preliminaryestimates suggest no abrupt methane contribution to the envi-ronment from hydrates in the immediate future.

IntroductionNatural-gas hydrates (clathrates) are crystalline, ice-like sol-ids that form when small (

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1,200 water molecules) and the solubility of water dissolvedin methane gas (1 water molecule in 1,000 methane mol-ecules) are low compared to their high concentrations inhydrate, hydrate forms most easily at phase interfaces wherethere is an abundance of both hydrocarbon and water.

Specifically, for gas+water systems, hydrate forms at thegas/water interface. However, for gas+water+oil systems,hydrate typically forms at the interface between the twoliquids, water and oil, from small gas molecules dissolvedin the oil. This interfacial phenomenon is a key concept inunderstanding hydrate formation and prevention.

Example: Hydrates in Flow Assurance. A case study ofhydrate formation is shown in the pressure/temperaturediagram ofFig. 1 for a deepwater flowline fluid. To the right,at high temperature and moderate pressure in the diagram,hydrates will not form and the system will exist in the fluid(hydrocarbon and water) region. However, hydrates willform in the shaded region at lower temperatures markedHydrate-Forming Region, so hydrate-prevention measuresshould be taken.

In Fig. 1, at 7 miles from the subsea wellhead, the flowingstream retains some reservoir heat, thus preventing hydrates.

The ocean cools the flowing stream, and at approximately9 miles, a unit mass of flowing gas and associated waterenters the hydrate region to the left of the hydrate-formationcurve, remaining in the uninhibited hydrate area until mile45. By mile 30 the temperature of the pipeline system iswithin a few degrees of the deep ocean temperature (40F).To prevent hydrate formation and blockage, approximately23 wt% methanol, with some safety factor, is required in thefree-water phase to shift the hydrate-formation region to theleft of flowline conditions, to prevent hydrate formation andpotential blockage. As vaporized methanol flows along thepipeline from the injection point at the wellhead in Fig. 1, itdissolves into any produced or condensed water.

Hydrate blockages occur in the free water, usually just

downstream from water accumulations where there is achange in flow geometry (e.g., a bend or pipeline dip alongan ocean-floor depression), or some nucleation site (e.g.,sand or weld slag). Hydrate inhibition occurs at the interfaceof the aqueous liquid, which contains most of the methanol,rather than in the bulk vapor, or oil/condensate.

This example illustrates hydrate avoidance, attained byinjecting sufficient methanol in the gas to partition 23 wt%methanol in the free water, thus preventing the flowlineconditions from entering the hydrate thermodynamic-sta-bility region. However, high water production requires largeamounts of methanol to be injected, making the economicspoor and sometimes impractical. Therefore, methods otherthan avoidance have been considered.

Thermodynamics PredictionsSuccessful avoidance is enabled by newer-generationhydrate programs for thermodynamic-formation-conditionpredictions with and without inhibitors. Fig. 2 shows theaccuracy of five common hydrate-prediction software pro-grams compared against published uninhibited-hydrate-equilibrium data as of 2002 for single-, binary-, and terna-ry-hydrate-guest molecules, as well as natural gases, blackoils, and gas condensates. Earlier programs provided onlythe initial limits of hydrate formation. New thermodynam-ic-program generation is based on hydrate-phase measure-ments and can predict useful additional conditions, such as

hydrate-phase amounts.Fig. 2 shows that the average absolute error in tempera-

ture for the five prediction programs was within 1 K. On apressure basis, predictions can be expected to be accurateto within 10%. These prediction errors approximate theerrors of the experiments and are acceptable for engineer-ing purposes. It may not be practical to improve predictionsfor the majority of cases. However, improved hydrate-thermodynamics measurements and predictions are needed,particularly for high (>50 wt%) concentrations of inhibitorsand those mixtures.

Thermodynamics predictions enable the flow-assuranceengineer to avoid hydrate-formation conditions in a flow-

DISTINGUISHED AUTHOR SERIES

Fig. 1Hydrate-formation pressures and tempera-tures as a function of methanol concentration in freewater for a given gas mixture. Flowline-fluid condi-tions are shown at distances along the bold blackcurve (Notz 1994).

TABLE 1HISTORY OF TRIENNIAL INTERNATIONAL

CONFERENCES ON GAS HYDRATES

Date City/Sponsor(s)

Number of

Papers/

Authors

June 1993 New York/New YorkAcademy of Sciences 61/130

June 1996 Toulouse/cole Nationale

Suprieure d'Ingnieurs de

Gnie Chimique

87/195

July 1999 Salt Lake City/New York

Academy of Sciences

104/258

May 2002 Yokohama/Keio University 204/500

June 2005 Trondheim/Statoil 247/330

July 2008 Vancouver/University of

British Columbia and

National Research Council, Canada

417/500+

Hydrate-

freeregion

f

Hydrate-

formation

curve

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Fig. 2Absolute-temperature errors in common prediction simulators compared against all published hydro-carbon-hydrate-formation data (single, binary, and ternary refer to the types of guest molecules; BO=blackoil; GC=gas condensate; sH=hydrate structure).

line, but at a cost of insulation for high temperatures, or ofinhibitor injectioncosts that may become unacceptable formarginally economic production projects.

Hydrate-Risk ManagementIn a growing number of flow-assurance situations, hydrate-risk management is more economical than avoidance. Oneaspect of hydrate-risk management is to allow hydrate par-ticles to form, but to prevent hydrate-particle aggregationto a blockage by ensuring that the particles will flow, andremain entrained in the oil phase. To move from avoidanceto risk management, it is essential to quantify hydrate-for-mation time dependence, on the basis of conceptual picturesdescribed below.

In hydrate kinetics, most of the initial quantitative kineticdata came from the laboratory of Bishnoi and his colleaguesat the University of Calgary. Hydrate-kinetics experimentsare difficult because hydrate formation is confounded byoverriding transient phenomena such as heat- and mass-transfer effects. A strict separation of all three effects (i.e., for-mation kinetics, mass transfer, and heat transfer) is requiredfor acceptable modeling.

Hydrate Blockages in Oil-Dominated Systems. Fig. 3 is a

conceptual representation, with input from J.A. Abrahamson(University of Canterbury, Christchurch, NZ), for hydrateformation in an oil-dominated system with

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5. The formation and dissociation of hydrates can causecoalescence of water drops in water-in-oil systems. Thiscoalesced free-water phase is prone to hydrate-blockageformation.

6. Like other deposits, freshly formed hydrates are moreporous and malleable than are hydrates that have time to ageand solidify. The aging process (something akin to Ostwaldripening) causes a more-dense crystal mass, making dissocia-tion of the plug increasingly difficult.

Cold Stabilized Flow. The above qualitative rules of thumbhave many flow-assurance applications, and they are quanti-fied in software programs that can predict approximatelywhere and when hydrates can form in oil-dominated flow-lines. However, it may be worthwhile to consider one pat-ented application that may be field-tested in the near future.

There are two main, patented, cold or stabilized flow con-cepts (Lund et. al. 2004; Talley et al. 2007). In each process,the key principle is to emulsify and convert free water tohydrate as entirely and rapidly as possible. Without a free-water phase to encourage hydrate-particle aggregation, as inRules of Thumb 3 and 4 in the preceding subsection, hydrateparticles will not aggregate but will flow with the oil phase,much like dry snow is difficult to compact/aggregate into asnowball. Conversely, without a significant gas phase, insuf-ficient hydrate may form to plug a flowline.

Hydrate Blockages in Condensate Systems. Light con-densate systems differ from oil-dominated systems becauseemulsified water droplets do not form without high shearbecause of low viscosity and the lack of surface-active com-ponents. There is a severe lack of published hydrate fielddata for condensate-flowline plugs, although the generalnarrowing of the flow path for hydrate formation has gained

acceptance, as shown in Fig. 4.Three additional rules of thumb for hydrate formation

from a condensate were determined by measurements in aliquid/condensate flow loop (Nicholas et al. 2009), in con-junction with several laboratory measurements of adhesiveforces between condensate hydrates and pipe materials.

1. Hydrates formed in bulk condensate may not deposit onthe wall in the absence of water-wet walls.

2. Hydrates formed at the pipe surface will remain on thewall.

(a) High concentrations of dissolved water provide a uni-form, dispersed deposit along the flowline.

(b) Free water results in a localized, early deposit as the

flowline enters the hydrate-stability region.3. Hydrate deposits can be dissociated with or withoutchemicals by flowing an undersaturated condensate past thehydrate deposit, and by use of methanol dissolved in thehydrocarbon. Typically, methanol is injected into the flowlinewhere it reaches equilibrium with the species present.

With hydrate deposition on flowline walls, the mecha-nism for condensate-hydrate-plug formation may differsignificantly from that of an oil-dominated-system plug.In condensate systems, sloughing and particle jamminglikely will occur to form a plug. In oil-dominated systems,particle aggregation will increase the apparent viscosity foreffective plugging. Sloughing and jamming are subjects ofcurrent research.

The above rules of thumb have several important implica-tions for the operation of a condensate flowline. For exam-ple, if a platform dehydrator operation has failed such thatfree water occurs, the export line should be shut for imme-diate remediation. However, if dissolved water is above thehydrate-equilibrium concentration, then corrective actionmay be taken by bringing the dehydrator to acceptable limits,for dissolution of the hydrate wall deposit.

Future of Hydrates in Flow AssuranceThe above conceptual representation presents a beginningfor understanding phenomena associated with hydrate-plugformation in relatively low-water-cut systems. The concepts

provide suggestions for incorporation in transient multi-phase-flow software to enable the flow-assurance engineerto determine the risk of hydrate-plug formation in an oil-dominated flowline. In addition, the concepts may be used todeal with systems that fail to meet design expectations, andthat are found to be at risk. These conceptual representationsare being extended to other cases in which a free-water phaseexists in addition to emulsified water in oil.

In the next decade, it may be possible for a flow-assuranceengineer to determine the risk of flowline plugging resultingfrom hydrate formation by three steps.

1. Obtain an uncontaminated sample of an oil for a newfield.

Fig. 4Hydrate formation narrowing the channel bywall deposition, (Courtesy of G. Hatton, formerly ofSouthwest Research Institute). Note: The bent tubeat the top blows nitrogen against the window forvisibility.

Fig. 3Conceptual representation of hydrate forma-tion in an oil-dominated system.

Water

Oil

Time/Distance Hydrate Shells

Water

Entrainment

Hydrate-Shell

GrowthAgglomeration Plug

Gas

Capillary Attraction

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2. Perform bench-scale hydrate tests to determine emul-sion characteristics with chemistry and shear over a repre-sentative temperature range.

3. Forecast plug-formation risk by use of the fluid infor-mation from Step 2 and transient multiphase computersoftware.

With risk assessment in hand, the engineer can determinewhich prevention steps are required. Ultimately, such riskassessments must be validated against field data for hydrateformation.

In Nature: Energy and Climate ChangeTwo excellent reviews of hydrates in nature have beenpublished by the National Petroleum Council (Kleinberg2007) and by the Council of Canadian Academies (Graceet al. 2008). The enormous potential for hydrated energy isindicated by the worldwide amount of methane in hydrates,with estimates ranging from 0.9401017 scf, and maybe almost two orders of magnitude greater than conven-tional reserves.

In the US, the relative magnitudes of hydrate and con-ventional gas are shown in Fig. 5. Current estimates of thevolume of natural gas trapped in hydrates within the US areon the order of 200,000 Tcf. Even if only a small fraction of

this volume is recoverable, this natural-gas resource couldprovide an enormous contribution relative to the current USdomestic consumption level (22 Tcf/yr) and expected futuregrowth in demand.

However, it is important to note two vital starting points. The total amount of methane in the ocean is uncer-

tain, but estimated to be greater than that in the perma-frost by a factor of 100, although permafrost hydratesmay be more accessible and frequently have higher con-centrations.

It is not only the total amount of hydrate, but also theconcentration and location of the resource that determinesrecoverability of methane from hydrates in nature. In Fig. 5

for example, the recovery of methane from the lower por-tion of the hydrate pyramid (with limited permeability) isproblematic.

Relative to the amount of conventional gas available,methane from hydrates is considered precommercial; there-fore, industry/government partnerships are required fordevelopment. Countries with a high energy demand suchas Japan, India, China, and South Korea are mounting largecampaigns to develop hydrated energy; the goal for Japan iscommercial productivity by 2015.

Because of space limitations, summary statements areprovided below with details that may be investigated in thecited references. Natural hydrates most likely are to be foundin sandy sediments because silty sediments typically havelean hydrate accumulations (Grace et al. 2008). In the 2002Mallik well, hydrates were determined to be pore-fillingand provided some mechanical stability to the sediment.Depressurization is thought to be the most economical wayto produce hydrates.

The technology and economics of hydrates in Arcticpermafrost and hydrates in the marine environment are suf-ficiently different and must be treated separately.

Arctic-Permafrost Hydrates.

There are no great technical deterrents to recovery ofenergy.

Hydrates have been produced for short periods in the2007 Mt. Elbert well (Boswell et al. 2008), and in the 6-day2008 Mallik depressurization, which had average flow ratesof 70 Mcf/D, with peak rates as high as 160 Mcf/D (Grace etal. 2008).

Hydrates have, as the largest technical concern, wellbore/reservoir geomechanical stability during production.

Hydrates require continuous multiyear production test-ing to enable reservoir modelers to eliminate transient effectsacceptably and to assess commercial feasibility (Kleinberg2007).

Fig. 5Hydrate resource (left) relative to the conventional natural-gas resource (right) for the United States(Boswell and Collett 2006).

Arctic sandstones under existing infrastructure (10s of Tcf in place)

Arctic sandstones away from infrastructure (100s of Tcf in place)

Deepwater sandstones (1,000s of Tcf in place)

Nonsandstone marine reservoirs with permeability (unknown)

Massive surficial and shallow nodular hydrate (unknown)

Marine reservoirs with limited permeability (100,000s of Tcf in place)

Reserves (200 Tcf)

Expected reserves growth (500 Tcf)

Undiscovered (1,500 Tcf recoverable)

Remaining unrecoverable (unknown)

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Hydrates provide an opportunity, during such produc-tion tests, for innovative technologies to be assessed such asCO2 displacement of CH4.

Hydrates provide an acceptable place (ease of access,high concentrations at sweet spots) for developments thatcan be transferred to the ocean in the future.

Hydrates may be recoverable economically, particu-

larly in places where there is access to existing infrastructure(Walsh et al. 2009).

Marine Gas Hydrates. These resources are less advanced developmentally than

Arctic-permafrost hydrates because gas from marine hydrateshas not yet been produced.

These resources have a major technology challenge of areliable method to find hydrates. (Kleinberg 2007). The com-mon bottom-simulating reflector is a first-order-detectionmethod, which frequently is unreliable.

These resources require a multisite drilling expeditionfor reliable assessment and recovery, which would have

a very high expense. The 2006, 113-day offshore Indianhydrate-exploratory expedition required USD 36 million.International cooperation is required to share expenses andresults.

These resources have unconventional hydrate-gas-recov-ery economics that are two to three times more expensivethan conventional offshore gas, when existing infrastructureis unavailable for either (Walsh et al. 2009).

Climate Change. While hydrate production is expected tohave no unusual environmental concerns, methane evolu-tion from natural hydrate deposits is considered here. Theisotopic record supports global warming from hydrated-methane evolution approximately 600 million years ago.More recently, there is conflicting evidence from analysisof the isotopic record from the late Quaternary. It appearsthat hydrates may have been relatively stable for the last10,000 years (Grace et al. 2008). Little is known aboutmethane evolution from hydrates in nature. Methane maybe oxidized before reaching the upper atmosphere. Themost-active locations for methane evolution likely are inthe marine permafrost. Hydrated-methane evolution is notexpected to be a major environmental factor in this cen-tury. Any methane evolution is likely to be chronic, ratherthan abrupt.

Conclusion

For the last three-quarters of a century, hydrates have beena major flow-assurance concern to the oil and gas industry.Progress in quantifying hydrate formation provides the engi-neer with new flow-assurance tools, both in oil-dominatedand condensate-dominated systems. In the future, it may bepossible to predict the hydrate-plug risk of an oil-productionsystem from a few simple measurements, aided by transientmultiphase software, to indicate emulsion stability and jam-ming of hydrated particles.

Currently, natural-gas hydrates are precommercial andrequire government/industry partnerships to prove viability.With increasing international cooperation, the next decadewill witness methane production from hydrates as a member

of the energy-resource spectrum. The climate change fromhydrates likely is chronic, rather than abrupt.

Dedication

This article is dedicated to Yuri F. Makogon, on the occasionof his retirement after a career of hydrate development.

ReferencesBoswell, R., Amato, R., Coffin, R., Collett, T., Dellagiarino, G.,

Fisk, R., Gettrust, J. et al. 2006. An Interagency Roadmapfor Methane Hydrate Research and Development. US DOEOffice of Fossil Energy (July 2006), http://www.fe.doe.gov/programs/oilgas/publications/methane_hydrates/mh_inter-agency_plan.pdf. Downloaded 22 September 2009.

Boswell, R. and Collett, T. 2006. The Gas Hydrates ResourcePyramid. Fire In The Ice (The National Energy TechnologyLaboratory Methane Hydrate Newsletter) Fall 2006: 57.

Boswell, R., Hunter, R., Collett, T., Digert, S., Hancock, S.,and Weeks, B. 2008. Investigation of Gas Hydrate BearingSandstone Reservoirs at the Mount Elbert Stratigraphic

Test Well, Milne Point, Alaska. Proceedings of the 6thInternational Conference on Gas Hydrates, Vancouver,Canada. 610 July.

Grace, J., Collett, T., Colwell, F., Englezos, P., Jones, E., Mansell,R., Meekison, J.P. et al. 2008. Energy From Gas Hydrates:Assessing the Challenges and Opportunities for Canada.Expert Panel on Gas Hydrates Project Report, Council ofCanadian Academies, Ottawa, Canada (September 2008),http://www.scienceadvice.ca/documents/(2008-11-05)%20Report%20on%20GH.pdf. Downloaded 22 September2009.

Kleinberg, R.L. 2007. Topic Paper 24: Hydrates. In Facingthe Hard Truths about Energy, National Petroleum CouncilReport, Washington, DC (18 July 2007), http://www.npchardtruthsreport.org/. Downloaded 22 September 2009.

Lund, A., Lysne, D., Larson, R., and Hjarbo, K.W. 2004. Methodand system for transporting a flow of fluid hydrocarbonscontaining water. US Patent No. 6,774,276; International(PCT) Patent No. WO/2000/025062; Norwegian PatentNo. NO 311,854.

Nicholas, J.W., Koh, C.A., and Sloan, E.D. 2009. A prelimi-nary approach to modeling gas hydrate/ice deposition ina liquid condensate system. AIChE Journal 55 (7): 18891897. doi: 10.1002/aic.11921.

Notz, P.K. 1994. Discussion of the Paper The Study ofthe Separation of Nitrogen from Methane by HydrateFormation Using a Novel Apparatus. Annals of the New

York Academy of Sciences 715 (1): 425429. doi: 10.1111/j.1749-6632.1994.tb38855.x.

Sloan, E.D. Jr. and Koh, C.A. 2008. Clathrate Hydrates ofNatural Gases, third edition, Vol. 119. Boca Raton, Florida:Chemical Industries, CRC Press.

Talley, L.D., Turner, D.J., and Priedeman, D.K. 2007. Methodof generating a non-plugging hydrate slurry. International(PCT) Patent No. WO/2007/095399.

Walsh, M.R., Hancock, S.H., Wilson, S.J., Patil, S.L., Moridis,G.J., Boswell, R., Collett, T.S., Koh, C.A., and Sloan, E.D.2009. Preliminary report on the commercial viability of gasproduction from natural gas hydrates. Energy Economics31 (5): 815823. doi:10.1016/j.eneco.03.006. JPT

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