TRCO Changes of Cryogenic Amine Plants 20110912

Embed Size (px)

Citation preview

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    1/18

    ChangesofCryogenic,AminePlant

    andStandardPlantConcept

    ByThomas H.Russell

    7050 South Yale, Suite 210Tulsa, Oklahoma 74136

    Phone (918) 481-5682

    The Gas Process ing Experts www.thomasrussellco.com

    Copyright2011,ThomasRussellCo.

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    2/18

    The Gas Process ing Exper t s Copyright2011,ThomasRussellCo.

    2CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    CryogenicandAminePlantDesignandFabricationChangesOverthePast40YearsPresentedatNTGPANovember4th, 2010 UpdatedSeptember6th,2011

    CryogenicPlants Introduction The Bill Randall Legacy Todays Process Opportunities Process Designs Available Today Challenges With Rich Inlet Gas- Slugs, Mol Sieves, Refrigeration Ethane Recovery and Ethane Rejection- Product Markets Modularization- How Big Can You Skid Mount? Standardization- Improved Delivery and Operating Flexibility

    AminePlants Introduction

    The Charles Perry Legacy Proprietary Amines vs. Generic Amines Inlet Gas Treating or Product Treating- Which Is Best? Acid Gas Content- How Much H2S Is With the CO2? Equipment Selection- Filtration, Rich/Lean Exchange, Stainless Steel Modularization- Ease of Field Installation Standardization- Many Amine Flow Rates, Common Flow Scheme

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    3/18

    The Gas Process ing Exper t s Copyright2011,ThomasRussellCo.

    3CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    CryogenicPlantsIntroductionThe first successful application of the turbo-expander process for recovery of gas liquids was in 1964. Coastal

    States built a 130 MMscfd plant to process the gas supplied to the city of San Antonio. Pressure was let down from

    the pipeline pressure of 600 to 700 psig to the city gate pressure of 300 psig.

    Ethane recovery of 30 to 40% and propane recovery of 80 to 90% No recompression required Methanol injection to inhibit hydrate formation Ethane price was about three cents per gallon

    Up to this time LPG recovery was primarily by lean oil absorption, with refrigerated lean oil absorption becoming

    popular in the 1950s.

    By 1970, the demand for ethane had increased and more expander plants were being built.

    Desired ethane recovery of 85 to 90% Residue gas recompressed to pipeline pressure Molecular sieve dehydration Ethane price was 20 to 30 cents per gallon by 1980

    TheBillRandallLegacyWhen you talk about the development of the turbo-expander plant, you have to start with Bill Randall.

    He worked for Delta Engineering when they built the

    Coastal plant in 1964. In 1972 he formed the Randall

    Corporation with Jerry Gulsby, Don Rawlings and

    others.

    By 1977 Randall Corporation had built over 60

    turbo-expander plants, and 70% of them were 15

    MMscfd or smaller. The 15 MMscfd plant was a

    standardized design, one-size-fits-all. And it is a

    truly packaged plant;

    The cold separator is in the base of thedemethanizer and the tower is on- skid

    The plate-fin exchangers are on-skid The mol sieve vessels are on-skid The rotoflow expander is on-skid

    After more than 40 years, we still see many Randall

    plants in operation. The Randall Corporation

    pioneered the standardized and packaged turbo-

    expander plant.

    TodaysProcessOpportunitiesFast forward to today and we see ethane prices of 30

    cents per gallon at Conway and 55 cents per gallon at

    Mont Belvieu. We are currently seeing a low margin

    (frac-spread) on ethane (10 to 15 cents per gallon at

    Mont Belvieu). On the upside, the propane price of

    about one dollar per gallon yields a margin of 50 to

    60 cents per gallon. And, the shale gas plays in the

    lower 48 states have significantly increased the

    amount of gas for processing.

    In 2008 the shale gas production was 2.02 trillion

    cubic feet, or 10% of total U S production. Reserves

    had increased 51% over the 2007 numbers.

    [SeeAppendixA: ShaleGasintheUnitedStates]

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    4/18

    The Gas Process ing Exper ts Copyright2011,ThomasRussellCo.

    4CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    This increase in available gas has held the price down

    to about $4.00 per mmBtu, and has dampened the

    enthusiasm for drilling somewhat. However, the

    favorable frac-spread for liquid products has

    continued to stimulate the process plant demand.

    And, most of the new gas liquid recovery plants use

    an expander.

    ProcessDesignsAvailableTodayAmerican ingenuity and technology have produced

    many innovations to the early industry standard

    single stage (ISS) expander plant process. A few

    familiar to me, but by no means all that are available

    to the industry, include;

    Ortloff Engineers, LTD- Recycle SplitVapor(RSV), Gas Subcooled (GSP), OverheadRecycle (OHR), , Carbon Dioxide Control

    (CDC), Single Column Overhead Reflux

    (SCORE), and others

    Randall Gas Technologies- High PressureAbsorber (HPA), Super Hy-Pro TTC, NGL-

    MAX, and NGL-PRO

    IPSI, LLC- Constrained Maximum Recovery(C-MAR)

    Most turbo-expander plant process innovations have

    been developed to accomplish specific goals

    including:

    Lower residue gas compression horsepower Higher ethane recovery Higher propane recovery with ethane rejection Higher carbon dioxide freeze tolerance

    The Ortloff GSP process is now in public domain,

    and is probably the most commonly used process in

    the lower 48 states. The Ortloff SCORE process

    obtains a 99% propane recovery in the ethane

    rejection mode. This process is very popular

    overseas, in areas where there is no ethane market but

    a high margin on the propane product.

    ChallengeswithRichInletGasProcessing nominally lean gas in the 2 to 3 GPM

    ethane-plus range is ideal for the ISS or GSP process.

    Shale gas production typically runs richer and offers

    special challenges:

    Liquid condensation in the pipeline results inslugs which must be dealt with at the plant.

    Very rich gas is liable to condense liquid on themol sieve bed. One foot of sacrificial materialsuch as Sorbead on top of the bed is good

    insurance.

    Inlet gas with four GPM plus will definitelyrequire refrigeration within the expander plant

    process.

    Inlet gas richer than six or seven GPM willprobably require refrigeration upstream of the

    expander plant.

    EthaneRecoveryandRejectionThere are at least two

    scenarios that require the

    expander plant to operate in

    the ethane rejection mode:

    The margin forrecovering ethane is

    negative, that is, the net

    value of the ethane as a

    liquid product is below

    the Btu value of ethane

    in the residue gas.

    There is no ethane market available, that is,there is no Y Grade pipeline economically

    accessible to the plant.

    We are currently seeing a slightly negative margin on

    ethane at Conway. And, there is no ethane market in

    the Marcellus Shale area of New York, Pennsylvania,

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    5/18

    The Gas Process ing Exper t s Copyright2011,ThomasRussellCo.

    5CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    and West Virginia. These possibilities require that

    each expander plant be built with the capability of

    ethane recovery or rejection. In rejection, the LPG

    product may have to meet different standards,

    depending on the reason for rejection.

    Most stringent- produce a propane-plus productwith only enough ethane that the product can be

    fractionated to an HD-5 propane. This is about

    6 or 7 mol percent ethane in the propane.

    Less stringent- produce an LPG product whichcan be transported in propane tanker trucks.

    This product will have a maximum vapor

    pressure of 225 psig with an ethane recovery of

    15 to 25%.

    Least stringent- reduce the ethane content of theLPG because of a low margin, but without a

    vapor pressure limitation. The amount of ethanerejection will be limited by the reboiling

    capacity of the demethanizer.

    In all cases the deethanizer reboiler must be heated

    by an outside heat source, because the tower bottom

    temperature will be warmer than the inlet gas. A heat

    medium system or compressed residue gas are both

    commonly used.

    ModularizationThe advantages of skid-mounting are many:

    More assembly work is done in the shop at alower hourly rate and not subject to weather

    Equipment and parts are more readily availableat the shop location, closer to supplies

    Much assembly work can be completed prior tofield move in, while waiting on permits and

    weather

    Equipment, piping, and instrumentation can bechecked out prior to shipment to field

    [SeeAppendixB: SkidMountingSavesTime

    andMoney]

    When Bill Randall skid-mounted a 15 MMscfd

    expander plant, nearly all of the equipment was on

    skid. It is a different story when you skid mount a

    200 or 300 MMscfd plant.

    The three mol sieve vessels will be 7 feet indiameter

    The Demethanizer tower will be 6 feet diameterat the bottom, and 100 feet tall

    The Cold Separator will be up to 9 feet indiameter

    The plate-fin exchangers will be 3 to 4 feetwide by 4 to 6 feet deep by up to 20 feet tall

    The pipe size will typically be 10 to 18 inchIPS, and one pipe-turn with 2 elbows takes 3 to

    5 feet

    When an expander plant is this large, much of the

    major equipment will be off-skid. Still, the

    advantages of skid mounting remain. Smaller

    vessels, pumps, control valve loops, and other

    equipment can be skid mounted beneficially. Above

    250 to 300 MMscfd the plant becomes more or less

    stick-built.

    StandardizationA standard plant is built to accommodate a range of

    gas volumes and compositions. The advantages are:

    Cost equipment, piping, skid layouts, andplot plan are designed once and duplicated on

    subsequent plants

    Delivery front-end time is saved onequipment design and selection, piping and skid

    design, minor material take-off lists and

    purchasing

    Flexibility the inlet gas conditions canchange or the plant can be moved to a new

    location

    Over the past five years the expander plant market

    has been delivery driven. With the shale gas boom

    and frac- spread profitability, our customers wanted

    their plant to ship last week. Standard plants have

    been our answer.

    We offer four standard expander plants, 40 MMscfd,

    60 MMscfd, 120 MMscfd, and 200 MMscfd. Each

    one is designed to process gas from 3 to 7 GPM

    ethane-plus.

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    6/18

    The Gas Process ing Exper ts Copyright2011,ThomasRussellCo.

    6CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    Table 1: Number of Expander Plants by Year Sold

    Capacity 2005 2006 2007 2008 2009 2010 2011 Total

    40 MMscfd 2 1 5 1 9

    60 MMscfd 3 2 2 1 8

    120 MMscfd 1 3 2 1 1 2 10

    200 MMscfd 1 1 1 1 5 12 21

    The trend has been toward bigger plants. EPC contractors have recently built 300 MMscfd, 450 MMscfd, and 600

    MMscfd plants in the States, and overseas plant sizes have reached 1.5 Bscfd.

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    7/18

    The Gas Process ing Exper t s Copyright2011,ThomasRussellCo.

    7CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    AminePlantsIntroductionAmine treating; also known simply as gas treating, gas sweetening and acid gas removal, refers to a group of

    processes that use aqueous solutions of various alkanolamines (commonly referred to simply as amines) to remove

    carbon dioxide (CO2) and hydrogen sulfide (H2S) from natural gas or gas-liquid product. It is a common process

    used in gas gathering facilities, natural gas processing plants and refineries. Most modern cryogenic plants require

    some form of amine treatment to:

    Remove CO2 from the inlet gas to prevent freeze-out in the cryo plant, and/or to Remove CO2 and H2S from the inlet gas or Y Grade product to meet the liquid product specifications.

    Gas and/or liquid treating usually employ an alkanolamine water solution using MEA, DEA, MDEA or other

    amine. The first amine gas sweetening patent was issued to R.R. Bottoms in 1930. The traditional absorber-stripper

    arrangement used today was developed by Girdler Corporation, and is called the Girbotol Process.

    TheCharlesPerryLegacyJust as Bill Randall is the father of the expander

    plant, Charles Perry is the patriarch of the packaged

    amine plant. In 1967 Charles and his wife formed a

    company and bought out Portable Treaters, which

    consisted of 10 amine plants, each about 5 gpm

    circulation. Unable to sell them to Shell, they made a

    deal to operate them, and the concept of Contract

    Treating was born.

    Later, Houston Natural needed a 60 MMscfd treating

    plant running in 90 days. Portable Treaters met the

    deadline with a plant built partially of used

    equipment. The deal was done on a handshake, no

    contract. Those were the good old days. Charles

    Perry also patented the charcoal filter which is

    standard in every amine plant today.

    ProprietaryAminesvsGenericAminesHow has the selection of amines progressed over the

    past 60 years? See Table 2 below:

    Table 2: Amine selection over the past 60 years

    Amine Wt % Amine mol/mol loading First used

    MEA 15 to 20 0.30 to 0.40 1940s

    DEA 25 to 35 0.35 to 0.45 1950s

    MDEA & Blended 45 to 55 0.45 to 0.60 1970s

    Proprietary 45 to 55 0.45 to 0.60 1980s

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    8/18

    The Gas Process ing Exper t s Copyright2011,ThomasRussellCo.

    8CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    MDEA gained popularity because of the lower

    circulation and lower reboiler duty required. But

    MDEA has a lower CO2 absorption rate. This

    enhances the tertiary amines usefulness for selective

    H2S removal, but reduces its value for bulk CO2

    removal. [See Appendix C Tertiary Amines]

    Hence the development of the proprietary amines

    with accelerators to speed up this reaction, and

    corrosion inhibitors to protect equipment from

    corrosive by-products like bicine. Today over 75%

    of new plants start up with a proprietary amine.

    Today we are talking about standard amine treaters

    and I have not discussed the other good acid gas

    solvents such as: Diglycolamine, Selexol, and

    Sulfolane. These are all patented-licensed processes

    which are available for special applications.

    InletGasTreatingvsProductTreatingThe expander plant designer is frequently confronted

    with the choice between treating the inlet gas and

    treating the product. Higher acid gas contents always

    mandate treating the inlet gas to meet residue gas

    specifications. Carbon dioxide contents above about

    one mol percent usually require inlet gas treating to

    avoid CO2 freeze-up in the Demethanizer. The exact

    break-over point depends on the richness of the gas.

    If you do treat the inlet gas, treating it down to about500 ppmv CO2 will eliminate the need for product

    treating. This depends on the Y Grade spec, is it

    0.35% CO2/C2 or 1000 ppmw CO2?

    Comments from group discussion

    Some important facts were mentioned by the group

    attending the paper:

    1. Treating the inlet gas water saturates it. This

    puts added demand on the Cryo plant inlet mol

    sieves.

    2. Treating the product water saturates it. Normal

    water specs for the Y-Grade pipeline are no

    free water at 34F. The product will enter the

    pipeline at a warmer temperature, and water

    will separate as the product cools to ground

    temperature. Untreated product is bone dry

    coming from the expander plant.

    3. There are not many good, simple ways to dry

    the product.

    AcidGasContentMost of the expander plant inlet gas we see today has

    only traces of H2S present. The gas or liquid treater

    will pick this up with no problem. A problem with

    the Still overhead arises as the H2S content increases.

    Rather than vent CO2 directly to the atmosphere, it

    may be necessary to; flare it, incinerate it or install a

    Claus Unit to safely dispose of the H2S.

    EquipmentSelectionGood filtration is an important component of amine

    plant design and operation;

    The inlet gas should pass through a reverse flowcoalescer, removing liquid droplets and solidparticles down to 0.3 microns

    A rich amine filter removing solid particlesdown to 5 microns. If the inlet gas contains

    much H2S, filter change-out can be hazardous!

    A full flow lean amine filter removing solidparticles down to 5 microns is sometimes used

    in the larger units

    A 10 to 20% side stream activated carbon filteris most commonly used

    A particulate filter downstream of the carbonfilter is most commonly used to catch charcoalfines. Sometimes a basket strainer would do the

    job.

    A particulate filter upstream of the charcoalfilter is sometimes used, so that the charcoal

    filter does not also act as a particulate filter

    requiring more frequent bed change outs

    Each designers personal preference dictates the

    filtration system, but every good amine system will

    have an inlet gas filter, a full flow rich or lean filter,

    and a side stream charcoal filter. A new charcoal

    filter should be back-flushed to remove fines before itis put on line.

    The Rich/ Lean Amine Exchanger is most commonly

    a plate-and-frame unit. These exchangers offer

    effective heat transfer area at an economical price.

    All wetted parts are stainless steel, and they offer a

    small footprint for skid mounting. Careful selection

    of the gasket material prevents degradation from

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    9/18

    The Gas Process ing Exper t s Copyright2011,ThomasRussellCo.

    9CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    hydrocarbon liquids such as aromatics. The flow

    passages within the exchanger can be plugged by

    particles larger than 1.5 mm. A 20 mesh cone

    strainer upstream can protect each side from

    plugging.

    It is important to use stainless steel in piping andequipment most subject to erosion-corrosion. The

    stainless material should always be 316L. All carbon

    steel material in contact with the amine solution

    should be stress relieved and be designed with a

    liberal corrosion allowance. Amine liquid velocities

    should be limited to five or six feet per second.

    ModularizationAmine plant equipment is ideal for skid mounting.

    For the regeneration portion of the plant, the

    equipment and pipe sizes fit well on the normal skid.I have skid mounted regeneration units up to 1500

    gpm amine circulation. In the contactor section the

    inlet filter and treated gas scrubber can normally be

    skid mounted, but the contactor will probably be off

    skid.

    StandardizationThe amine regeneration system lends itself well to

    standardization. The sizes are graduated by gpm

    amine circulation, in steps dictated by the pipe

    diameter to meet the required 5 to 6 feet per second

    velocity.

    Please see the example presented in Table 3 below.

    Table 3: Example amine circulation velocity

    3 IPS 120 gpm 5 6 feet/second

    4 IPS 200 gpm 5 6 feet/second

    6IPS 450 gpm 5 6 feet/second

    Most of the equipment in the regeneration section can

    be sized to meet each standard gpm flow rate. There

    is an exception in the difference between gas and

    liquid treaters. There may also be an exception in the

    type of amine chosen, for example: DEA and

    MDEA.

    The contactor section is sized specifically for each

    gas or liquid flow rate. Gas contactor size is based

    on gas volume and amine flow rate. But, various

    sizes of Contactors can match up with one standard

    size regen package. For example a 400 gpm gas

    treater might be treating 100 MMscfd of 3% CO2 gas

    or 300 MMscfd of 1% CO2 gas.

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    10/18

    The Gas Process ing Exper t s Copyright2011,ThomasRussellCo.

    10CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    [APPENDIXA]SHALEGASINTHEUNITEDSTATESSource: Wikipedia, www.wikipedia.org

    IntroductionShalegasintheUnitedStatesis

    rapidlyincreasingasasourceof

    naturalgas.Ledbynew

    applicationsofhydraulic

    fracturingtechnologyand

    horizontaldrilling,development

    ofnewsourcesofshalegashas

    offsetdeclinesinproduction

    fromconventionalgas

    reservoirs,andhasledtomajor

    increasesinreservesofUS

    naturalgas. Largelydueto

    shalegasdiscoveries,estimated

    reservesofnaturalgasinthe

    UnitedStatesin2008were35%higherthanin2006.[1]

    In2007,shalegasfieldsincludedthe#2(Barnett/NewarkEast)and#13(Antrim)sourcesof

    naturalgasintheUnitedStatesintermsofgasvolumesproduced.[2]

    TheeconomicsuccessofshalegasintheUnitedStatessince2000hasledtorapiddevelopmentof

    shalegasinCanada,and,morerecently,hasspurredinterestinshalegaspossibilitiesinEurope,

    Asia,andAustralia.

    U.S.shaledepositsalsocrossoverintoCanadianprovinces,suchasOntario.[3]

    USShaleGasProductionUSshalegasproductionhasgrownrapidlyinrecentyearsasthenaturalgasindustryhas

    improveddrillingandextractionmethodswhileincreasingexplorationefforts[4]. USshale

    productionwas2.02trillioncubicfeet(TCF)in2008,ajumpof71%overthepreviousyear.[5] In

    2009,USshalegasproductiongrew54%to3.11Tcf,whileremainingprovenUSshalereservesat

    yearend2009increased76%to60.6TCF.[6] InitsAnnualEnergyOutlookfor2011,theUSEnergy

    InformationAdministration(EIA)morethandoubleditsestimateoftechnicallyrecoverableshale

    gasreservesintheUS,to827Tcffrom353Tcf,byincludingdatafromdrillingresultsinnewshale

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    11/18

    The Gas Process ing Exper t s Copyright2011,ThomasRussellCo.

    11CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    fieldssuchastheMarcellus,HaynesvilleandEagleFordshales. Shaleproductionisprojectedto

    increasefrom14%oftotalUSgasproductionin2009to45%by2035.[7]

    TheavailabilityoflargeshalegasreservesintheUShasledsometoproposenaturalgasfired

    powerplantsaslowercarbonemissionreplacementsforcoalplants,andasbackuppowersources

    forwindenergy.[9][10]

    In2011,though,anewsreportfoundthat"noteveryoneintheEnergyInformationAdministration

    agrees"withtheoptimisticprojectionsofreserves,andquestionedtheimpartialityofsomeofthe

    reportsissuedbytheagency. Twooftheprimarycontractors,IntekandAdvancedResources

    International,whichprovidedinformationforthereportsalsohavemajorclientsintheoiland

    gasindustry. "ThepresidentofAdvancedResources,VelloA.Kuuskraa,isalsoastockholderand

    boardmemberofSouthwesternEnergy,anenergycompanyheavilyinvolvedindrillingforgas"in

    theFayettevilleShale,accordingtothereportinTheNewYorkTimes. ThecurrentEIA

    administrator,RichardG.Newell,avocalsupporteroftheindustryprospects,announcedinJune

    his

    plans

    to

    resign

    to

    take

    a

    job

    at

    Duke

    University.

    [11]

    The

    news

    report

    and

    one

    from

    the

    previous

    dayonthesamegeneralsubjectbythesamejournalistattractedcritiquesfrombloggersatForbes

    andtheCouncilonForeignRelations,tonametwo.[12][13] DianeRehmhadUrbina;Seamus

    McGraw,writerandauthorof"TheEndofCountry";TonyIngraffea,aprofessorofengineeringat

    Cornell;andJohnHanger,formersecretaryofPennsylvaniaDepartmentofEnvironmental

    Protection;onaradiocallinshowaboutUrbino'sarticlesandthebroadersubject. The

    associationsrepresentingthenaturalgasindustry,suchasAmerica'sNaturalGasAlliance,were

    invitedtobeontheprogrambutdeclined.[14]

    "The development of shale gas is expected to significantly increase U.S. energy

    security and help reduce greenhouse gas pollution."

    White House, Office of the Press Secretary, 17 November 2009[8]

    HistoryIn1996,shalegaswellsintheUnitedStatesproduced0.3TCF(trillioncubicfeet),1.6%ofUSgas

    production;by2006,productionhadmorethantripledto1.1TCFperyear,5.9%ofUSgas

    production.By2005therewere14,990shalegaswellsintheUS.[15]Arecord4,185shalegaswells

    werecompletedintheUSin2007.[16]

    ShalegasbylocationAntrimShale,MichiganTheAntrimShaleofUpperDevonianageproducesalongabeltacrossthenorthernpartofthe

    MichiganBasin.[17]AlthoughtheAntrimShalehasproducedgassincethe1940s,theplaywasnot

    activeuntilthelate1980s. Duringthe1990s,thealdrillingisnotwidelyused. Unlikeothershale

    gasplayssuchastheBarnettShale,thenaturalgasfromtheAntrimappearstobebiogenicgas

    generatedbytheactionofbacteriaontheorganicrichrock.[1]

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    12/18

    The Gas Process ing Exper t s Copyright2011,ThomasRussellCo.

    12CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    In2007,theAntrimgasfieldproduced136billioncubicfeetofgas,makingitthe13thlargest

    sourceofnaturalgasintheUnitedStates.[18]

    BarnettShale,TexasTheBarnettShaleoftheFortWorthBasinisthemostactiveshalegasplayintheUnitedStates.

    ThefirstBarnettShalewellwascompletedin1981inWiseCounty.[19]

    Drillingexpandedgreatlyinthepastseveralyearsduetohighernaturalgaspricesanduseofhorizontalwellstoincrease

    production. Incontrasttooldershalegasplays,suchastheAntrimShale,theNewAlbanyShale,

    andtheOhioShale,theBarnettShalecompletionsaremuchdeeper(upto8,000feet). The

    thicknessoftheBarnettvariesfrom100to1,000feet(300m),butmosteconomicwellsarelocated

    wheretheshaleisbetween300and600feet(180m)thick. ThesuccessoftheBarnetthasspurred

    explorationofotherdeepshales.

    In2007,theBarnettshale(NewarkEast)gasfieldproduced1.11trillioncubicfeetofgas,makingit

    thesecondlargestsourceofnaturalgasintheUnitedStates.[20] TheBarnettshalecurrently

    produces

    more

    than

    6%

    of

    US

    natural

    gas

    production.

    [21]

    CaneyShale,OklahomaTheCaneyShaleintheArkomaBasinisthestratigraphicequivalentoftheBarnettShaleintheFt.

    WorthBasin. TheformationhasbecomeagasproducersincethelargesuccessoftheBarnett

    play.

    ConesaugaShale,AlabamaWellsarecurrentlybeingdrilledtoproducegasfromtheCambrianConasaugashaleinnorthern

    Alabama.[22]ActivityisinSt.Clair,Etowah,andCullmancounties.[23]

    FayettevilleShale,

    Arkansas

    TheMississippianFayettevilleShaleproducesgasintheArkansaspartoftheArkomaBasin. The

    productivesectionvariesinthicknessfrom50to550feet(170m),andindepthfrom1500to6,500

    feet(2,000m). Theshalegaswasoriginallyproducedthroughverticalwells,butoperatorsare

    increasinglygoingtohorizontalwellsintheFayetteville.ProducersincludeSEECOasubsidiaryof

    SouthwesternEnergyCo.whodiscoveredtheplay,ChesapeakeEnergy,NobleEnergyCorp.,XTO

    EnergyInc.,ContangoOil&GasCo.,EdgePetroleumCorp.,TrianglePetroleumCorp.,and

    KerogenResourcesInc.[24]

    FloydShale,AlabamaTheFloydShaleofMississippianageisacurrentgasexplorationtargetintheBlackWarriorBasin

    ofnorthernAlabamaandMississippi.[25][26]

    GothicShale,ColoradoBillBarrettCorporationhasdrilledandcompletedseveralgaswellsintheGothicShale.Thewells

    areinMontezumaCounty,Colorado,inthesoutheastpartoftheParadoxbasin.Ahorizontalwell

    intheGothicflowed5,700MCFperday.[27]

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    13/18

    The Gas Process ing Exper ts Copyright2011,ThomasRussellCo.

    13CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    HaynesvilleShale,LouisianaAlthoughtheJurassicHaynesvilleShaleofnorthwestLouisianahasproducedgassince1905,ithas

    beenthefocusofmodernshalegasactivityonlysinceagasdiscoverydrilledbyCubicEnergyin

    November2007. TheCubicEnergydiscoverywasfollowedbyaMarch2008announcementby

    ChesapeakeEnergythatithadcompletedaHaynesvilleShalegaswell.[28] Haynesvilleshalewells

    havealsobeendrilledinnortheastTexas,whereitisalsoknownastheBossierShale.

    NewAlbanyShale,IllinoisBasinTheDevonianMississippianNewAlbanyShaleproducesgasinthesoutheastIllinoisBasinin

    Illinois,Indiana,andKentucky. TheNewAlbanyhasbeenagasproducerinthisareaformore

    than100years,butrecenthighergaspricesandimprovedwellcompletiontechnologyhave

    increaseddrillingactivity.Wellsare250to2,000feet(610m)deep.[2] Thegasisdescribedas

    havingamixedbiogenicandthermogenicorigin.

    PearsallShale,TexasOperators

    have

    completed

    approximately

    50

    wells

    in

    the

    Pearsall

    Shale

    in

    the

    Maverick

    Basin

    of

    southTexas. ThemostactivecompanyintheplayhasbeenTXCOResources,althoughEnCana

    andAnadarkoPetroleumhavealsoacquiredlargelandpositionsinthebasin.[29]Thegaswellshad

    allbeenverticaluntil2008,whenTXCOdrilledandcompletedanumberofhorizontalwells.[30]

    Devonianshales,AppalachianBasinChattanoogaandOhioShalesTheupperDevonianshalesoftheAppalachianBasin,

    whichareknownbydifferentnamesindifferentareas

    haveproducedgassincetheearly20thcentury. The

    mainproducingareastraddlesthestatelinesof

    Virginia,WestVirginia,andKentucky,butextends

    throughcentralOhioandalongLakeErieintothe

    panhandleofPennsylvania. Morethan20,000wells

    producegasfromDevonianshalesinthebasin. Thewellsarecommonly3,000to5,000feet(1,500

    m)deep.TheshalemostcommonlyproducedistheChattanoogaShale,alsocalledtheOhio

    Shale.[31] TheUSGeologicalSurveyestimatedatotalresourceof12.2trillioncubicfeet(350km3)

    ofnaturalgasinDevonianblackshalesfromKentuckytoNewYork.[3]

    MarcellusShaleTheMarcellusshaleinWestVirginia,Pennsylvania,andNewYork,oncethoughttobeplayed

    out,isnowestimatedtohold168516TCFstillavailablewithhorizontaldrilling.[32] Ithasbeen

    suggestedthattheMarcellusshaleandotherDevonianshalesoftheAppalachianBasin,could

    supplythenortheastU.S.withnaturalgas.[33] InNovember2008,ChesapeakeEnergy,whichheld

    1.8millionnetacresofoilandgasleasesintheMarcellustrend,solda32.5%interestinitsleases

    toStatoilofNorway,for$3.375billion.[34]

    DrillingahorizontalshalegaswellinAppalachia

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    14/18

    The Gas Process ing Exper t s Copyright2011,ThomasRussellCo.

    14CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    UticaShale,NewYorkInOctober2009,theCanadiancompanyGastem,whichhasbeendrillinggaswellsintothe

    OrdivicianUticaShaleinQuebec,drilledthefirstofitsthreestatepermittedUticaShalewellsin

    NewYork.ThefirstwelldrilledwasinOtsegoCounty.[35]

    WoodfordShale,OklahomaTheDevonianWoodfordShaleinOklahomaisfrom50to300feet(91m)thick.Althoughthe

    firstgasproductionwasrecordedin1939,bylate2004,therewereonly24WoodfordShalegas

    wells. Byearly2008,thereweremorethan750Woodfordgaswells.[36][4] Likemanyshalegas

    plays,theWoodfordstartedwithverticalwells,thenbecamedominantlyaplayofhorizontal

    wells. TheplayismostlyintheArkomaBasinofsoutheastOklahoma,butsomedrillinghas

    extendedtheplaywestintotheAnadarkoBasinandsouthintotheArdmoreBasin.[37] Thelargest

    gasproducerfromtheWoodfordisNewfieldExploration;otheroperatorsincludeDevonEnergy,

    ChesapeakeEnergy,CimarexEnergy,AnteroResources,St.MaryLandandExploration,XTO

    Energy,PabloEnergy,PetroquestEnergy,ContinentalResources,andRangeResources.

    References1. JadMouawad,"Estimateplacesnaturalgasreserves35%higher,",NewYorkTimes,17June2009,

    accessed25October2009.2. USEnergyInformationAdministration,Top100oilandgasfields,PDFfile,retrieved18February2009.3. StopFrackingOntario:ShaleinOntario4. SimonMauger,DanaBozbiciu(2011)."HowChangingGasSupplyCostLeadstoSurgingProduction".

    http://www.ziffenergy.com/download/papers/Gas_Costs_Supply_%20Growth_April_2011_web_version.pdf.Retrieved20110510.

    5. USEnergyinformationAdministration,Shalegasproduction,accessed4December2009.6. USEnergyinformationAdministration,"Summary:USCrudeOil,NaturalGas,andNaturalGasLiquids

    ProvedReserves2009",http://www.eia.gov/pub/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/current/pdf/arrsummary.pdf,accessed5January2011.

    7. USEnergyInformationAdministration,http://www.eia.doe.gov/forecasts/aeo/executive_summary.cfm,referencedJanuary5,2011

    8. WhiteHouse,OfficeofthePressSecretary,StatementonU.S.Chinashalegasresourceinitiative,17November2009.

    9. PeterBehrandChristaMarshall,"Isshalegastheclimatebill'snewbargainingchip?,"NewYorkTimes,5August2009.

    10. TomGjelten,"Rediscoveringnaturalgasbyhittingrockbottom,"NationalPublicRadio,22September2009.

    11. Urbina,Ian,"BehindVeneer,DoubtonFutureofNaturalGas",TheNewYorkTimes,June26,2011.Retrieved20110627.

    12. Helman,Christopher,"NewYorkTimesIsAllHotAirOnShaleGas",Forbes,June27,20111:37pm.Retrieved20110627.

    13. Levi,Michael,"IsShaleGasaPonziScheme?",CouncilonForeignRelationswebsite,June27,2011.TheearlierUrbinaarticlewasEnronMoment:InsidersSoundAlarmamidaNaturalGasRush.Retrieved20110627.

    14. "NaturalGas:PromiseandPerils",DianeRehmShow,NPRviaWAMU,June28,2011.Retrieved20110629.

    15. VelloA.Kuuskraa,Reserves,productiongrewgreatlyduringlastdecadeOil&GasJournal,3Sept.2007,p.3539

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    15/18

    The Gas Process ing Exper t s Copyright2011,ThomasRussellCo.

    15CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    16. LouiseS.Durham,"Prices,technologymakeshaleshot,"AAPGExplorer,July2008,p.10.17. MichiganDEQmap:Antrim,PDFfile,downloaded12February2009.18. USEnergyInformationAdministration,Top100oilandgasfields,PDFfile,retrieved18February2009.19. ScottR.ReevbasinsinvigorateU.S.gasshalesplay,urnal,22Jan.1996,p.5358.20. USEnergyInformationAdministration,Top100oilandgasfields,PDFfile,retrieved18February2009.21. USEnergyInformationAdministration:IsU.S.naturalgasproductionincreasing?,Accessed20March

    2009.22. AlabamaStateOilandGasBoard(Nov.2007):AnoverviewoftheConesaugashalegasplayinAlabama,

    PDFfile,downloaded10June2009.23. "OperatorschasegasinthreeAlabamashaleformations,"Oil&GasJour.,21Jan.2008,p.4950.24. NinaM.Rach,TrianglePetroleum,KerogenResourcesdrillingArkansas'Fayettevilleshalegas,Oil&Gas

    Journal,17Sept.2007,p.5962.25. MarkJ.PawlewiczandJosephR.hatch,PetroleumAssessmentoftheChattanoogaShale/FloydShale

    TotalPetroleumSystem,BlackWarriorBasin,AlabamaandMississippi,USGeologicalSurvey,DigitalDataSeriesDDS691,2007,PDFfile.

    26.AlabamaGeologicalSurvey,AnoverviewoftheFloydShale/ChattanoogaShalegasplayinAlabama,July2009,PDFfile.

    27. "BarrettmayhaveParadoxBasindiscovery,"RockyMountainOilJournal,14Nov.2008,p.1.28. LouiseS.Durham,"Louisianaplaya'companymaker',"AAPGExplorer,July2008,p.1836.29.AlanPetzet(20070813)."MoreoperatorseyeMaverickshalegas,tarsandpotential".Oil&GasJournal

    (PennWellCorporation)107:3840.http://www.ogj.com/index/articledisplay/303130/sarticles/soilgasjournal/svolume105/sissue30/sexplorationdevelopment/smoreoperatorseyemaverickshalegastarsandpotential.html.Retrieved20090707.

    30. "MaverickfracsunlockgasinPearsallShale".Oil&GasJournal(PennWellCorporation)107:3234.20070825.http://www.ogj.com/index/articledisplay/337639/sarticles/soilgasjournal/svolume106/sissue32/sexplorationdevelopment/smaverickfracsunlockgasinpearsallshale.html.Retrieved20090707.

    31. RichardE.Peterson(1982)AGeologicStudyoftheAppalachianBasin,GasResearchInstitute,p.40,45.32. UnconventionalnaturalgasreservoirinPennsylvaniapoisedtodramaticallyincreaseUSProduction

    2008011733. ArthurJ.Pyron(20080421)."Appalachianbasin'sDevonian:morethana"newBarnettshale"".Oil&

    GasJournal(PennWellCorporation)106(15):3840.http://www.ogj.com/index/articledisplay/326309/sarticles/soilgasjournal/svolume106/sissue15/sexplorationdevelopment/sappalachianbasinrsquosdevonianmorethanalsquonewbarnettshalersquo.html.Retrieved20090707.

    34. "Chesapeakeannouncesjointventureagreement",WorldOil,December2008,p.106.35. TomGrace,"Officialspositivefollowinggaswelltour,"OneontaDailyStar,7October2009.36. TravisVulgamoreandothers,"Hydraulicfracturingdiagnosticshelpoptimizestimulationsof

    WoodfordShalehorizontals,"AmericanOilandGasReporter,Mar.2008,p.6679.37. DavidBrown,"BigpotentialboostsWoodford,"AAPGExplorer,July2008,p.1216.

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    16/18

    The Gas Process ing Exper ts Copyright2011,ThomasRussellCo.

    16CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    [AppendixB]

    SkidMountingSavesTime&Money

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    17/18

    The Gas Process ing Exper ts Copyright2011,ThomasRussellCo.

    17CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    HHOOWW BBIIGG CCAANN YYOOUU SSKKIIDD MMOOUUNNTT??

  • 8/4/2019 TRCO Changes of Cryogenic Amine Plants 20110912

    18/18

    The Gas Process ing Exper t s Copyright 2011 Thomas Russell Co

    18CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years

    www.thomasrussellco.com

    [AppendixC]TertiaryAminesSource:12thEditionoftheGPSAdatabookpage216

    Unlikeprimaryandsecondaryamines,thenitrogen(N)intertiaryamines(RRRN)hasnofree

    hydrogen(H)torapidlycarbamateasperoverallEq.213.Asaconsequence,theremovalofCO2

    bytertiaryaminescanonlyfollowtheslowroutetobicarbonatebyEq.214andcarbamatebyEq.

    215.

    Theslownessofthisreactionleadingtobicarbonateistheunderlyingreasonwhytertiaryamines

    can

    be

    considered

    selective

    for

    H2S

    removal,

    by

    playing

    with

    absorption

    contact

    time,

    and

    this

    attributecanbeusedtofulladvantagewhencompleteCO2removalisnotnecessary.

    However,theslowroutetobicarbonatestheoreticallyallowsatequilibriumachemicalloading

    ratioofonemolorCO2permolofanime. Furthermore,athighpartialpressure,thesolubilityof

    CO2intertiaryaminesisfargreaterthanintheprimaryandsecondaryamines,thusfurther

    enhancingtheCO2loadingbyphysicalsolubilityathighpartialpressures.