trco changes of cryogenic amine plants 20110912
TRANSCRIPT
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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.
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2CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years
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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
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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]
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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,
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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.
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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.
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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
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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
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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.
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[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
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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]
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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]
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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
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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
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15CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years
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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.
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[AppendixB]
SkidMountingSavesTime&Money
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17CryogenicandAminePlantDesignandFabricationChangesoverthePast40Years
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HHOOWW BBIIGG CCAANN YYOOUU SSKKIIDD MMOOUUNNTT??
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[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.