6th International Conference on Gas Hydrates


You don't seem to have a PDF reader installed, try download the pdf

Item Metadata


ICGH2008logoPakulskiSzymczak.pdf [ 219.28kB ]
JSON: 1.0040962.json
JSON-LD: 1.0040962+ld.json
RDF/XML (Pretty): 1.0040962.xml
RDF/JSON: 1.0040962+rdf.json
Turtle: 1.0040962+rdf-turtle.txt
N-Triples: 1.0040962+rdf-ntriples.txt
Original Record: 1.0040962 +original-record.json
Full Text

Full Text

TWELVE YEARS OF LABORATORY AND FIELD EXPERIENCE FORPOLYETHER POLYAMINE GAS HYDRATE INHIBITORSMarek Pakulski?  and Steve SzymczakBJ Chemical Services11211 FM 2920 W, Tomball, Texas, 77375USAABSTRACTThe chemical structure of polyether amines (PEA), mainly electron donating multiple oxygen andnitrogen atoms as well as active hydrogen atoms, make such compounds actively participating inthe formation of hydrogen bonds with surrounding molecules.  Hydrophobic polypropyleneglycol functionality gives PEA's properties of multi-headed surfactants having hydrophilic aminegroups.  These groups have a strong affinity for water molecules, ice and hydrate crystals.  SuchPEA compounds have been known for several years.  However, the hydrate inhibition propertiesof PEA?s were only discovered about twelve years ago.  The first discovery stimulated moreresearch in laboratories and led to practical applications for hydrate inhibition in gas fields.  Aninteresting property of PEAs is their synergistic effect on hydrate inhibition when appliedconcurrently with polymeric kinetic hydrate inhibitors (KHI) or thermodynamic inhibitors (THI).The combination inhibitors are better inhibitors than a single component one.  Quaternizedpolyether diamines are efficient antiagglomerant (AA) hydrate inhibitors while differentderivatization can produce dual functionality compounds, i.e. corrosion inhibitors/gas hydrateinhibitors  (CI/GHI). With all of this versatility, PEAs found application for hydrate inhibition inoil and gas fields onshore and offshore in production, flowlines and completion. The PEAs havean excellent record in protecting gas-producing wells from plugging with hydrates.    Keywords: gas hydrates, kinetic inhibitors, polyether amine, hybrid hydrate inhibitor                                                     ?  Corresponding author: Phone: 281-357-2708 Fax 281-357-2701 E-mail: mpakulski@bjservices.comNOMENCLATUREAA AntiagglomerantBHA Bottom Hole AssemblyCI Corrosion InhibitorGHI Gas Hydrate InhibitorHHI Hybrid Hydrate InhibitorJ-T Joule-Thomson cooling effect upon gasexpansionKHI, KI Kinetic Hydrate InhibitorLDHI  Low Dosage Hydrate InhibitorMPa   Megapascal Pressure UnitPEA    Polyether Aminep/T Pressure and Temperature conditionsS(I) Small Cage Hydrates, C1, C2S(II) Small and Larger Hydrates C1-C5THF TetrahydrofuranTHI  Thermodynamic Hydrate Inhibitor? T    Hydrate Subcooling TemperatureINTRODUCTIONGas hydrates form when water moleculescrystallize around guests molecules.  Thewater/guest crystallization process has beenrecognized since its discovery by Sir HumphreyDavy in 1810, is well characterized and occurswith sufficient combination of pressure andtemperature [1].  Light hydrocarbons, methane-to-heptanes, nitrogen, carbon dioxide and hydrogensulfide are the guest molecules of interest to thenatural gas industry.  Depending on the pressureand gas composition, gas hydrates may build up atProceedings of the 6th International Conference on Gas Hydrates (ICGH 2008),Vancouver, British Columbia, CANADA, July 6-10, 2008.           - 2 -any place where water coexists with natural gas attemperatures as high as 30?C (~85? F).Hydrates formation in oil and gas operations is agrowing problem as producers drill in arcticregions and deeper, cooler waters offshore.Hydrates can form in the wellbore as the fluids gothrough pressure and temperature change resultingin J-T cooling.  They also form in the flow linesbetween wellheads and separation facility.Hydrates create physical barriers to production andmust be inhibited or if formed, dissolved, in orderfor gas production to occur.  The operator mustmaintain the well and a production line free ofhydrates all of the time.  Formation of gas hydratescan be eliminated or hindered by several methods.Thermodynamic prevention methods control oreliminate elements necessary for hydrateformation: the presence of hydrate forming guestmolecules, the presence of water, high pressureand low temperature.  The elimination of any oneof these four factors from a system would precludethe formation of hydrates.  Unfortunately,elimination of these hydrate elements is oftenimpractical or even impossible.  Transmissionlines heating and insulating is a commonmechanical solution to hydrate problemsencountered in long subsea pipelines.  Hydrateswill never form if the gas/water system is keptabove the hydrate formation temperature.  Gasdehydration is another method of removing ahydrate component.  However, in a practical fieldoperation, water can be economically removed to acertain vapor pressure only and residual watervapors are always present in a dry gas.  Hydrateplugs in "dry" gas lines have been reported [2].There are several approaches to hydratesprevention, dissolution and inhibition.  Forexample Hale, et al [3] patented a method ofpreventing hydrates formation in gas wells withthe addition of polycyclicpolyether polyols.  Theaddition of chemicals to the gas/water streams isthe most common method of preventing hydrateformation.  Large amounts of alcohols, glycols orsalts are being utilized.  These additivesthermodynamically destabilize hydrates andeffectively lower the temperature of hydrateformation.  However, hydrate prevention withmethanol or glycol can be quite expensive due tothe high effective dosages required, 20% to 50%of the water phase.  Ethylene glycol is usuallyrecovered downstream and recycled whilemethanol is not usually recovered and poses anenvironmental problem. Large concentrations ofsolvents aggravate potential scale problems bylowering the solubility of scaling salts in water andprecipitating most known scale inhibitors [4].Replacing some of the high methanol volumerequired for treatment with non-thermodynamicinhibitors offers a significant cost reduction to gascompanies and pipeline operators.Work on new KHI and AA has progressed inmany research laboratories to the point ofsuccessful field tests and onshore and offshorecommercial applications [5-8].LABORATORY EXPERIMENTSEarly Discovery.Polyether amines have been known for severalyears and are commercially available from a fewmanufacturers.  They exist as both, specialty andcommodity chemicals.  One can distinguish thebasic structures of polyether amines as follows:Alkyl terminated polyether monoamines.R-(EO)a-(PO)b-(EO)a-(CH2)c-NR1R2 (1)Linear amine terminated polyether diamines andpolyamines.R1R2N[(PO)a(EO)b(PO)a(CH2)cCH(R1)NR1]nR2  (2)Branched polyether triamines:A[(PO)a-(EO)b-(PO)a-(CH2)c-CH(R1)-NR1R2]3   (3)where: a+b = 1 to >100, c = 1-6R = methyl to octadecyl group,R1,R2 = H, CH3, CH2-CH2-OHor CH(CH3)-CH2-OHPO and EO are inserted propylene oxide or/andethylene oxide moietiesA = trimethylolpropane or glycerin.A common property of all these compounds istheir ability to form multiple hydrogen bondsthrough oxygen, nitrogen and active hydrogenatoms.  Thus, they can associate with severalmolecules of water to attach themselves to ice andhydrate crystals.  This feature gained attention inthe early discovery process.Initial work on PEA hydrate inhibition propertiesstarted in the early 1990's.  The testing equipmentavailable at that time was limited to an ambientpressure, slow flowing 0.3 cm (1/8 inch) diameter,6 m (20 ft.) long stainless steel loop (Figure 1).           - 3 -A solution of 20% Tetrahydrofuran (THF) in 3.5%NaCl/water with and without additives wascirculated through the simulated pipeline at presettemperatures of -7 to -12?C.  The THF/salt watersolution simulates gas/water systems without thenecessity of running tests at high pressures withhighly flammable gas [9].  Typical concentrations ofthe tested additives were 0.05% to 0.5% active.  Thevolume of fluid inside the loop was 60 ml andallowed a 20-hr fluid residence time inside the loopat a pumping speed of 0.05 ml/min.  Testtemperatures were selected so that uninhibited fluidwould freeze within minutes and inhibited fluid inhours.  Build up of a backpressure in the simulatedgas pipeline was measured and recorded with time.A 15-micron filter located at the loop intake assuredthat pressure buildup did not occur from pluggingthe line with impurities, and that backpressure wascaused only by blockage with hydrate crystals beingformed in the simulated gas line cooled inside thecold bath. After completion of each test, the loopwas warmed up to 60?C (140? F), washed with waterand the next test fluid.PRESSUREGAUGEANDRECORDERRETURN LINEPUMP WITH ABACKPRESSURESAFETY CUT-OFFFLUIDRESERVOIR15 MICRONSFILTERSTAINLESS STEELCOILED TUBINGCOOLINGBATHFigure 1.  Schematic drawing of simulated gashydrate testing loop.The simple test equipment proved to be an efficienttool for pre-screening several PEA compoundsalong with known kinetic polymeric inhibitors(KHI) and glycols.  A library of promising PEAswas developed and used for high pressure testingwith natural gas.Development of Hybrid Hydrate Inhibitor.In typical field applications of PEA we were facingan existing alcohol storage and pumping facilitydesigned for high volume throughput.  Using theexisting equipment made more sense from theeconomical point of view than replacing it withsmaller pumps and tanks.  Instead of replacingpumps with smaller ones capable to deliverprecisely 1% of former methanol or ethylene glycolrate, PEA was put in solvent to use the same pumpsat 20-40% output [10].  After analyzing the fieldwork results, it was noticed that some PEA solutionsperformed better than expected.  This observationwarranted further look at the THI/KHI synergyphenomenon.Further experiments were performed in a custom-built 500 ml volume, 25 MPa pressure ratedtesting cell.  Gas pressure, temperature, stirrerspeed and torque are controlled and continuouslyrecorded.  The equipment was designed to test alltypes of hydrate inhibitors, THI, KHI and AA.The fluid was stirred at 250 rpm.  The highpressure testing was a two step process.  First, thecell was loaded with the fluid and gas, and fastcooled to the desired p/T conditions. Sometimes, aminor pressure adjustment was necessary at theend of this step.  Second, the fluid was kept atconstant temperature to the point of 10% gas tohydrate conversion.  The fluid was continuouslystirred during both steps or the stirrer could bestopped for a period of time to simulate gas flowstop and restart.  After the completion of each testthe cell was warmed up to 30?C (86? F) for 5hours, the old solution was drained and the cellwas flushed with a hot ~50?C (~120? F) solution ofthe next system to be tested, which was alsodrained.  Finally, the fresh test solution was addedto the cell, which was pressurized with a test gasand the cooling was activated.  This cell loadingprocedure sufficiently protects the experimentsintegrity by removing any hydrate residues fromthe previous test; thus, eliminating a water"memory" effect that causes accelerated hydrateformation in water/gas systems going throughhydrates/warm up cycles [11].Based on testing experience, 5% gas to hydrateconversion was established as an inhibitor failingpoint.  While this sounds somehow arbitrary, itcame from observations of several hundreds ofexperiments showing no increase in torquerequirement of the mechanical stirrer to maintain aconstant speed up to 5% gas intake.  A smallamount of hydrates is dispersed within the fluidand causes no viscosity increase or flowobstructions.   Each test was performed using 200 ml of hydrateinhibitor water solution and 20 ml of condensate.A well established laboratory benchmark, "GreenCanyon" gas mixture was used for testing (SIIhydrate).  Gas and condensate compositions are           - 4 -provided in Table 1.  Schematic drawing of theequipment is depicted in Figure 2.Component GreenCanyon Component CondensateHelium - C-5 8.15Nitrogen 0.4 C-6 16.8Methane 87.2 C-7 30.77Ethane 7.6 C-8 17.11Propane 3.1 C-9 10.09i-Butane 0.5 C-10 5.68n-Butane 0.8 C-11 4.08i-Pentane 0.2 C-12 3.18n-Pentane 0.2 C-13 2.22C-14 1.25-C-150.70-C-160.20C-17+ 0.49Table 1.  Green Canyon gas and condensate mole% composition.Figure 2.  Schematic drawing of the pressurevessel for hydrates testing.  A - stirrer speedregulator and current sensor, T - temperaturesensor, p - pressure sensorFigure 3 presents examples of hydrate formationrates in various mixtures of PEA and methanol inwater.  The mixtures were prepared starting with5% MeOH and 0% PEA, and subsequentlyreplacing each percent of MeOH with 0.135% ofPEA, i.e. 3.5% MeOH, 0.2% PEA or 1.25%MeOH, 0.5% PEA?etc.  The PEA:MeOH ratiowas in the 0 to 30 range.  The rationality behindsuch mixture formulations was to produce equalcost products.  The cost of methanol is about 14%of PEA price.  The system undertreated withmethanol will not produce any hydrates for somenumber of hours but converts gas to hydrates veryrapidly at a certain time. With larger proportionsof PEA in the mixture, the slope of curvesrepresenting gas to hydrate conversion with timedecrease.02468101214160 1224364860728496Time, hMol % conv.Uninhibited5% MeOH10% MeOH.2% PEA, 3.5% MeOH.5% PEA, 1.25%MeOHSUBCOOLING ? T 14?CGREEN CANYON GAS COMPOSITION, 760 psi/2?CFigure 3.  Hydrate formation rates with variousinhibitorsThe hydrate forming process sometimes startsearlier; however, it is very slow. The resultsillustrated in Figure 3 where, in the laboratory test,the combination of 0.2% PEA and 3.5% MeOHstarted producing hydrate after 39 hours at hydrateconditions.  The formula containing 0.5% PEAand 1.25% MeOH or 5% MeOH with no PEAshowed first signs of hydrate at 17 hours and 34hours respectively.  Notice, that if one uses 5% gasto hydrate conversion as inhibitor end of life, bothPEA/MeOH combinations are superior to 10%MeOH.  The addition of 5% or 10% methanolsignificantly shifts the hydrate equilibrium curvetoward lower temperatures.  The solvent additionlowers ? T value by 2? C (3.6? F) for 5% and 5? C(9? F) for 10%; however, at given p/T conditionsthe system remains at hydrate conditions.Consequently, both solutions made hydrates and inboth cases once the process started, its progresswas catastrophic.  The conversion curves arealmost vertical for MeOH being the only additiveCooler &HeaterTemperature control unitCoolingJacketSS VesselMagnet DriveMagneticallyCoupled StirrerGas inlet/outletpTAPLOTTERDATA LOGGER           - 5 -while hydrate forms slowly in the presence of thePEA/MeOH mixtures.  Practical consequences ofsuch "slow to fail" behavior is that in the fieldapplication, operators have more time to react ifhydrates form slowly versus an instant pluggingwells and lines if the hydrate forming process isfast.  Complete data indicate there is aperformance peak at a certain PEA/MeOH ratiorange and a commercial Hybrid Hydrate Inhibitor(HHI) was formulated to maximize benefits of thebest THI/KHI combination.  The inhibitor is beingapplied worldwide to treat S(II) hydrates. Itseffectiveness is particularly visible in gasproducing wells and flowlines subject totemperatures below freezing in cold environmentor due to J-T cooling effect.PEAs derivatization.It has been documented and described in literaturethat by reacting PEA with alkyl halides one createshydrate antiagglomerant (AA) [12] i.e. structure(2) n=1 reacts to form a quaternary compound (4).R1R2N(PO)a(EO)b(PO)a(CH2)cCH(R1)NR1R2 + RX         R1     R2N(PO)a(EO)b(PO)a(CH2)cCH(R1)NR1R2X (4)         R3Dahlmann et al. [13] patented several structures ofderivatized PEA being water soluble corrosion andgas hydrate inhibitors:orR = C1 - C22Structures (5) and (6) are examples of derivatizedtriethylene glycol diamine.  Inventors claim theseproducts are more biodegradable than classicquaternary corrosion and hydrate inhibitors.Additional PEA properties making them moreattractive hydrate inhibitors.Tubular and equipment iron corrosion is a wellrecognized problem in oilfield operations.Corrosion inhibitors (CI) are usually continuouslyinjected to every part of upstream or downstreamflow lines and corrosion mitigation costs makesignificant part of production chemical expenses.Chemical structure of PEAs indicates they mustscavenge oxygen and be capable to adhere tometal surfaces.  A systematic work on PEAsanticorrosion properties was published a few yearsago.  Hope et al. [14] reported results showing thatunderivatized PEAs are superior CI in soursystems.  They also counteract the corrosivenessof methanol (Table 2).  The economy of aproducing field can be improved if PEA can beLDHI/CI in one molecule and replace some or allof the commercial CI.Exp.Number CompositionCorrosionmm/yearPittingmm/year1 DI Water only 0.442 02 66% MeOH 0.324 11.73 66% MeOH,0.25% CI-C* 0.091 24 40% MeOH,+ PEA 0.193 0540% MeOH,0.25% CI-C* +PEA0.208 06 10% MeOH, +PEA 0.21 0710% MeOH,0.25% CI-C* +PEA0.191 0Table 2.  Corrosion rates of steel in sour solutionsat various conditions. *CI-C ? commercial CIMore enhancing properties are listed below:?   Being low freezing liquids they never buildsolid residues in pipes and equipment inpotential hot spots and don't require solventcarrier.?   Soluble in water or organic solvents includingaliphatic hydrocarbons.  Can be delivered inanhydrous solvent and then they partition intowater phase.  Solutions in glycols or heavierhydrocarbon solvents are safety qualified non-flammable.?   Unlike polymeric KHI, PEAs dissolvehydrates.?   Low toxicity, biodegradableMe-N-(EO)2CH2-CH2-N        (CH2)2                          (6)OCMeR COMe-N-(EO)2CH2-CH2-N        (CH2)2      NH2   (5)OCMeC10H21 HOC           - 6 -FIELD EXPERIENCEAs mentioned above gas hydrates in theproduction and transmission of oil and gasrepresent a significant operational issue for theproducing and transporting companies.  In order toproperly address and solve the problems related tohydrate formation the operator must know thecause in terms of the field conditions and find acost-effective solution.  Although it is possible tosuccessfully address hydrate issues throughmechanical and thermal means, it is typically not acost-effective measure.  For that reason theindustry has moved towards addressing hydrateproblems through two approaches, mechanical andchemical.Mechanical Means to Control Hydrates.The first approach is design.  In the gas productionscenario the design element will focus on waterelimination and temperature retention.  On theirown merits these design considerations typicallywill not take care of the problem alone.  Anexample of a design approach might be pipe-in-pipe sub-sea flow lines whereby a transmissionline is placed inside of an insulating line.  Theannular space between the pipes can be filled withan insulating material in order to retard the loss ofheat to the cooler external environment.  Anotherdesign approach is to fill the annular space in aproducing well with an insulating fluid [15].  Inboth of these approaches the intent is to provide aninsulating barrier between the produced fluid andthe external environment.Water removal in the gas production process ismore problematic.  In all normal cases theproduced water has to be produced up the wellwith the hydrocarbon.  Water removal is practicalin the production surface equipment prior to thepipeline.  Surface equipment specifically designedto separate and remove water is commonlyemployed in the process.  For land production thisseparation facility would be placed in a centrallocation where all well production commingled.In an offshore environment the separationequipment is placed on the hub platform.  Bear inmind that dehydrated gas, i.e. gas from which thefree water has been removed, still has water.  Thusit is not uncommon to see hydrates form downstream of the water separation plant.  This iscommonly caused by a localized J-T effect.Once the design measures are in place it istypically necessary to supplement the hydrateinhibition process through the addition of hydrateinhibitors.  As discussed above these range fromthe THI to the KHI and AA.  The experiences withselecting and administering the proper PEAinhibition chemistry will be the focus of theremainder of this discussion on field experience.Selection and Application of PEA Inhibitors.Further in this discussion the topics will split intocold weather environments, e.g. Canada, andoffshore environments, e.g. Gulf of Mexico.  Inthis section the discussion will focus on theselection and application criteria that are incommon with both production areas.In all applications it is necessary to gain anunderstanding of the water, gas, temperature andpressure conditions for a particular system.  Bearin mind that in all of the discussed applications theoperator was using a THI (usually methanol) or anLDHI (KHI or AA).  There were no cases wherethe initial application used the PEA.  In themajority of cases the operator was using methanol.There are software programs available that willpredict the methanol requirement for inhibitionbased on the various inputs.  In most cases thestarting feed rate of the PEA product was appliedbased on the methanol rate.  Various PEAproducts were used.  Some were a blend of THIand PEA and some were only PEA.  As discussedabove significant lab testing was also carried outto predict the sub-cooling of the PEA productsversus the standard (usually methanol).  Thistesting was necessary to confirm the range of PEAsub-cooling.  However, in all cases the actualapplication had a precedent of inhibitor treatment.Once the system is understood and the modelingconfirms the applicability of the PEA product it istime to initiate the field trial.  The field trial is themost visible step in the process by which the PEAchemistry replaces the incumbent product.  Thatvisibility is based on the reality that a failure in thefield has significant financial and operationalconsequences.The Field Trial.The field trial has several distinct steps.  It isnecessary to conduct the trial in a planned anddeliberative manner.  The goal of the field trial isthe successful application of the product with thedesired result of inhibiting hydrate formation.Because the record of the field trial will serve asthe primary product record it is imperative to makechanges one at a time.  More valuable applicationinformation has been lost due to simultaneous,           - 7 -multi-variable changes than to any other reason.Following are the prescribed steps for conductinga meaningful field trial:1.  Establish the current system by collectingrelevant data prior to the introduction of thenew product.  The operator and the chemicalfield personnel will determine the timenecessary to establish the benchmark and therelevant data.2.  Introduce the new chemical at a sufficientlyhigh feed rate so as to not starve the systemfor inhibitor.  During the transition fromoriginal chemical to the new chemical it isbest to err in favor of high dosage.3.  Calculate the time necessary to displace theoriginal product from the system.  This timeincludes displacement of the fill line anddilution of the product from the separationequipment.  A common rule of thumb is to usetwice the calculated time.  For example, if ittakes one day to displace the original chemicalfrom the fill line then run the new chemical fortwo days to insure that the performance datareflects the new product only.4.  Start to reduce the feed rate in definiteincrements in order to reach the desired feedrate.  This must be done in a fashion similar tothe original product turnover process.  If thefeed rate reductions are made too quickly thenit is impossible to determine the critical rate.If it took two days to see the results of the newproduct, then is would not be unreasonable totake one day to see the results of a feed ratereduction.5.  Upon seeing a negative response to a feed ratechange it is necessary to increase the rateabove the last performing rate.  This is donebecause a low rate will starve the system andjeopardize the operation.  Hence, once thelowest rate has been determined it is necessaryto raise the rate higher, gain control of thesystem and then begin to lower the rates again.6.  Once the system stabilizes begin returning tothe lowest rate at which the system ransmoothly.7.  Observe the system at this new rate.  If itmaintains performance then this is the newrate for the PEA.  Compare the empirical datawith the theoretical data in order to create abest fit curve for that particular application.It is obvious from the steps of the field trial whysingle variable changes are important.  Often is thecase where an operational problem coincided witha series of simultaneous independent changes.  Inthis case it is impossible to point to the cause andthe process must return to a prior condition forwhich the system was stable.Case Histories - Canada.Following are relevant case histories on theapplication of the PEA chemistry in a cold region.These break down in to four types of applications.These are downhole, well head, pipeline andunderground gas storage.Downhole.  Hydrates that form in the productiontubing must be attacked below the point offormation.  In order to do that the chemical mustbe applied in the well bore.  This is problematicand costly for wells that were not completed withthe appropriate chemical delivery system in place.An economical approach to delivering hydrateinhibitor below the point of hydrate formation isthe use of capillary tubing.  This tubing, typically0.25 or 0.375 inch OD is inserted through the topof the well and hung off above the perforationsand below the hydrate formation point as apermanent installation.  The chemical is fedthrough the line and is controlled by a BottomHole Assembly (BHA) that includes a one waycheck valve.Wellhead.  Commonly hydrates will form at thewellhead as a result of a pressure change and theresulting Joule-Thomson cooling.  To remedy thisproblem the PEA inhibitor is fed upstream of thepressure drop in order to have the inhibitor incontact with the fluids before the drop.Pipeline.  In cold weather regions hydrateformation in surface transmission pipelines is acommon occurrence.  The traditional approach hasbeen to feed methanol to provide thermodynamicinhibition.  As reported by Budd, et al. [10] theblended THI/PEA product provided superiorperformance when compared to methanol.  In acurrent application in Canada the operator wasfaced with a situation whereby a thermodynamicquantity of methanol could not be delivered to thepipeline due to volume restrictions.  In this casethe operator constantly fought freezing problemsand had to install line heaters at critical locationsto complement the methanol.  The THI/PEAproduct was applied and the hydrate problemsdissipated.  After monitoring the system for a           - 8 -period of time the operator turned off the lineheaters.  Here is a case where the methanol wasnot acting in the thermodynamic range and wastherefore ineffective.  The THI/PEA productrequired less volume than the methanol and couldbe applied in a quantity sufficient to provideinhibition.Gas Storage.  Gas usage is cyclical, but gasproduction is constant.  In order to store gas in thelow usage periods, i.e. warmer months, operatorspump natural gas into storage caverns.  During thecold months the gas is produced and sold to themarket.  During storage it is common for the watercontent of the gas to increase.  During subsequentwithdrawal of the gas form the caverns theincreased water leads to hydrate formationproblems.  An application of the PEA chemistryupstream of the initial pressure drop mitigateshydrate formation.Case Histories ? Gulf of Mexico.Following are relevant case histories on theapplication of the PEA chemistry in an offshoreenvironment.  These break down in to four typesof applications.  These are downhole, well head,flow line and pipeline.Downhole.  The difference between a downholetreatment offshore and one on land has to do withthe type of well completion.  Whereas a land wellcan receive a capillary line that runs internal to theproduction tubing an offshore well has a surfacecontrolled sub-surface safety valve that precludesany insertion of a capillary line.  Thus operatorsinstall capillary lines in the annular space betweenthe tubing and the casing and run the line belowthe hydrate zone and then enter the productiontubing through a specialty entry port.  In the eventthat the well was not constructed with a chemicalline below the hydrate zone or if that line isdamaged the operator must consider a workover.In a recent application on a deep water facility inthe Gulf of Mexico the operator produced from awell that had a chemical supply line placed belowthe hydrate producing zone in the well.  Theoperator fed methanol into the well to controlhydrates.  Because of the high volume ofmethanol, the increasing cost of methanol and thelogistical cost of transporting methanol to theplatform the operator looked for a cost-effectivealternative.A THI/PEA hydrate inhibitor was formulated andfed to this well.  Initial results indicated the wellperformed with the new inhibitor.  Subsequent tothe establishment of a satisfactory feed rate thewell experienced a hydrate upset.  The THI/PEAproduct was replaced with methanol.  Themethanol could not control the hydrate formationat the previous rate.  The operator determined thatcritical production changes occurred.  Currentlythe operator is preparing to put the THI/PEAproduct back on the well at a higher rate to see if itcan control the hydrates better than the methanol.Wellhead.  The most common application of thePEA chemistry in the Gulf of Mexico is for thecontrol of hydrates in fuel gas systems.  A portionof the gas that is produced onto a platform is usedas a fuel source to run platform equipment, e.g.gas compressors and turbines that generateelectricity.  This fuel gas goes through a separationprocess in which hydrates form under Joule-Thomson conditions.  The utilization of a PEAhydrate inhibitor for these applications controlshydrate formation and allows smooth operation ofthe platform.Flow lines.  Szymczak, et al. [16] reported on theuse of a THI/PEA inhibitor in the Gulf of Mexicoto control hydrate formation in a subsea flow line.In that case hydrates formed in the flow linebetween the producing well and the platform.Although this was shelf production (deep water isdefined as 1,000 feet of water depth or more) thesea temperature combined with the producingpressure was sufficient to create hydrates.Methanol was the standard treatment.  Due to thecost of methanol transport and the intermittenthydrate problems that occurred because themethanol rate was on the edge of thermodynamicinhibition, the operator switched to the THI/PEAproduct.  As a result of the change the flowpressure stabilized and the hydrate problemsdisappeared.Pipeline.  A flow line is different from a pipelinein that the flow line transports gas from the well tothe platform.  At that stage the gas still belongs tothe operator.  A transmission pipeline is a trunkline that takes gas from a variety of producingplatforms.  Pipeline applications of hydrateinhibitor are the most critical application.  Gulf ofMexico gas pipelines carry millions standard cubicfeet of gas per day.  A hydrate plug carries a high           - 9 -financial consequence.  A THI/PEA product is fedinto a pipeline.  This is a winter time applicationonly.CONCLUSIONSPolyether amines made slow nevertheless steadyadvance from the laboratory to single fieldapplication to several hundred applications aroundthe world.  Applied in combination with solventthey fill a niche between inexpensive high usagevolume of alcohols and extremely expensive;however, low usage volume polymeric KHI.Hydrate inhibition with PEA is a proventechnology.ACKNOWLEDGEMENTSAuthors thank the management of BJ ChemicalServices for approving the publication of this workand Dr. Mike Brown for helpful review comments.REFERENCES[1] Katz D.L., Prediction of Conditions of HydrateFormation in Natural Gases. Trans. AIME,160:140.[2] Kashou S.F., Subramanian S., Matthews P.,Subik D., Qualls D., Akey R., Carter J., ThummelL., Faucheaux E., Gulf of Mexico Export GasPipeline - Hydrate Plug Detection and Removal,OTC 16691, presented at the Offshore TechnologyConference in Houston, Texas, May 3 - 6, 2004.[3] Hale A.H., Dewan A.K.R., Blytas G.C. GasHydrate Inhibition, US Patent 5076364.[4] a) Kan A.T., Fu G., Tomson M.B.,  Effect ofmethanol on carbonate equilibrium and calcitesolubility in a gas/methanol/water/salt mixedsystem; Langmuir 2002, 18, 9713-9725;  b) KanA.T., Fu G., Tomson M.B.,  Effect of methanoland ethylene glycol on sulfates and halite scaleformation;  Ind. Eng. Chem. Res. 2003, 42, 2399-2408;  c) Tomson M.B., Kan A.T., Fu, G.Inhibition of Barite Scale in the Presence ofHydrate Inhibitors, SPE 87437, Presented at the6th International Symposium on Oilfield Scale,Aberdeen, UK, May 26-27, 2004.[5] Argo C.B., Blain R.A., Osborne C.G., PriestleyI.D.,  Commercial Deployment of Low DosageHydrate Inhibitors in a Southern North Sea 69Kilometer Wet-Gas Subsea Pipeline, SPE 37255,Presented at the SPE International Symposium onOilfield Chemistry in Houston, Texas, February18-21, 1997.[6] Fu S.B., Cenegy L.M., Neft C.S., A Summaryof Successful Field Applications of a KineticHydrate Inhibitor, SPE 65022, Presented at theSPE International Symposium on OilfieldChemistry in Houston, Texas, February 13-16,2001.[7] Frostman L.M., Przybylinski J.L.:  SuccessfulApplications of Anti-agglomerant HydrateInhibitors, SPE 65007, Presented at the SPEInternational Symposium on Oilfield Chemistry inHouston, Texas, February 13-16, 2001.[8] Pakulski M., Prukop G., Mitchell C., FieldTesting and Commercial Application of HighEfficiency Non-Polymeric Gas Hydrate Inhibitorin Offshore Platforms, SPE 49210, Presented atSPE Annual Technical Conference in NewOrleans, Louisiana, September 27-30, 1998.[9] Couch S.R., Davidson D.W, Can. J. Chem, 49,2691, (1971).[10] Budd D., Hurd D., Pakulski M., SchafferT.D., Enhanced Hydrate Inhibition in Alberta GasField, SPE 90422, Presented at the SPE AnnualTechnical Conference in Houston, Texas,September 26-29, 2004.[11] Miyazaki K., Yasuoka K., MolecularDynamics Simulation of Dissociation andFormation Process for Methane Hydrate,Presented at the Fourth International Conferenceon Gas Hydrates, Yokohama, May 19-23, 2002.[12] Pakulski M., Quaternized Polyether AminesAs Gas Hydrate Inhibitors, US Patent 6025302.[13] Dahlmann U., Feustel M., Additives forInhibiting Gas Hydrate Formation, US Patent7214814,  Corrosion and Gas Hydrate InhibitorsHaving Improved Water Solubility and IncreasedBiodegradability,  US Patents 7253138, 7323609,7341617.[14] Hoppe R., Martin R., Pakulski M., SchafferT.,  Corrosion Mitigation with Gas HydrateInhibitors, SPE 100474, Presented at the SPE GasTechnology Symposium in Calgary, Alberta,Canada, May 15-17 2006.[15] Wang X., Javora P., Qu Q., Pearcy R., A NewThermal Insulating Fluid and Its Application inDeepwater Riser Insulation in the Gulf of Mexico,SPE 84422, SPE Production and Facilities2005;20(1):35-40.[16] Szymczak S., Sanders K., Pakulski M.,Higgins T., Chemical Compromise: AThermodynamic and Low Dose Hydrate InhibitorSolution for Hydrate Control in the Gulf ofMexico,  SPE 96418, SPE Projects Facilities andConstruction 2006;21(6):1-5.


Citation Scheme:


Citations by CSL (citeproc-js)

Usage Statistics

Country Views Downloads
United States 7 3
City Views Downloads
Seattle 6 3
Ashburn 1 0

{[{ mDataHeader[type] }]} {[{ month[type] }]} {[{ tData[type] }]}
Download Stats



Customize your widget with the following options, then copy and paste the code below into the HTML of your page to embed this item in your website.
                            <div id="ubcOpenCollectionsWidgetDisplay">
                            <script id="ubcOpenCollectionsWidget"
                            async >
IIIF logo Our image viewer uses the IIIF 2.0 standard. To load this item in other compatible viewers, use this url:


Related Items