as Pha

Plant was initially designed tounable to fully strip the richproduce 150 MMcfd oftreated gas.

Train 1 was designed toremove 95% of acid gas from120 MMcfd raw gas in thesweetening unit.

30 MMcfd stream of rawgas bypasses the amine unitand combines with amineplant-treated gas to yield

DEA solution.

Lean solution loadings of0.60.7 mol of CO2/mol ofDEA were typical.

Fully stripped DEAshould contain lessthan 0.02 mol ofCO2/mol of DEA.

High solution leanloadings and solutionAppendix BJudge Digby GProduction witChange-Out1: C

Judge digby plant

The gas plant is operated by BP andis located in Pointe Coupee Parish inSouth Louisiana.

Plant came online in 1970.

Inlet feed stream composition(Table B-1)

DEA amine unit produces a salesgas with less than 3% CO2 and8 ppm H2S.

Consists of two trains

Train 1 consists of150 MMcfd conventionalamine unit using 30%DEA followed by a TEGdehydration unit.

Train 2 consists of100 MMcfd TEG dehydrationunit only.

Figure B-1 is an aerial view of theplant.

Train 1 is shown in the upperleft-hand corner.

Figure B-2 is the process flowdiagram of Train 1.DOI: 10.1016/B978-1-85617-982-9.00009-0Quick Solventse Study

150 MMcfd that meets thedesired CO2 and H2Sspecification.

Bypass gas is treated witha nonrecoverable H2Sscavenging chemical beforebeing blended with thesales gas.

In 1999 engineering study indicated

Maximum throughputwas between 135 and140 MMcfd capacitydeclined to 135 MMcfd.

Unit became unstable andrequired 24-h mannedoperation at production ratesgreater than 140 MMcfd.

DEA system exhibited severalproblems.

DEA solution had degradedand the reboilers wereseverely fouled.

Corrosion probes indicated ahigh degree of corrosion.

Regenerator still washydraulically limited andlant Hikes

degradation productsusually lead tocorrosion and reboilerfouling problems.

High CO2 loading in the DEAfrom the regenerator alsoprevented the absorber fromremoving all the CO2 from theraw gas; therefore, there wastoo much CO2 in the gasleaving the DEA unit.

Instead of treating andbypassing 122.5 and30 MMcfd, respectively, theplant could only treat and

FIGURE B-1 Judge Digby gas processing plant.

30 MMcfdsc

Bypass

Sourgas

Sweet gas

BTEXrecovery

Aminesweetening

unit de

FIGURE B-2 Judge Digby flow diagram

Table B-1 Typical InletFeed Stream.

Component Mole percent

CO2 8.08C1 89.54C2 1.15C3 0.18i-C4 0.08n-C4 0.05i-C5 0.05n-C5 0.03C6 0.57N2 0.27H2S ppm 40

170 Gas Sweetening and Processing Field ManualSweet,dry gas

Salesgas

Glycolhydrator

.H2Savenger

wAppendix B: Judge Digby Gas Plant Hikes Production 171135 MMCFD that containedless than 3% CO2.

Table B-2 shows the plantsperformance using DEA.

Debottlenecking

BP considered several options toregain lost capacity.

Contactor was hydraulically limitedto a feed rate of 120 MMcfd, whichalso limited BPs options.

Flow rates greater than thecontactors hydraulic limitresulted in

Large amine losses

Increased corrosion,andbypass 122.5 and13.5 MMcfd, respectively,to produce a combinedsales gas volume of only

Table B-2 Operating history

Inlet gas flow rate (MMcfd)Bypass gas flow rate (MMcfd)Gas flow rate to absorber (MMcfd)Inlet gas pressure (psig)Inlet gas temperature (F)DEA circulation rate (gpm)DEA concentration (wt%)Lean DEA loading (mol CO2/mol DEA)Lean DEA temperature (F)Rebolier duty (MMbtu/h)CO2 in outlet gas (%)Operating instabilities.

To maximize production, BP wantedto maximize

Bypass gas flow rate and

Amount of CO2 removed inthe absorber.

BP also wanted to reduce thenumber of plant upsets at highflow rates.

Plant is unmanned 16 h/day.

Upsets during unmannedperiods increase the numberand cost of off-shift operatorcallouts.

Each unplanned shutdownhad adverse effects onproducing wells.

BP decided to replace the existingDEA chemical solvent with DowsAP-814 solvent.

Requires less regenerationduty

Absorbs more CO2

Solvent change-out required

Less than 24 h withoutextensive system cleanoutand

No mechanical equipmentmodifications.

Preparing for theconversion

ith DEA

August 1999 July 2000

92.5 135.00 13.5

92.5 122.5994 100096 95

680 95330 330.02 0.06

113 11039.5 502.72 2.75Figure B-3 shows the

Amine contactor(background)

Regeneration still, and

Benzenetolueneethylbenzenexylene (BTEX)stripper (foreground).

Figure B-4 shows a process flowdiagramof the Train 1 amine system.

BP performed a gamma scan of theabsorber and regenerator beforethe solvent switch.

172 Gas Sweetening and Processing Field ManualAn engineering analysisof the reboiler showed itwas severely fouled.

Two cleaning crews manned theshutdown to ensure timely cleaningof the reboiler tubes.

FIGURE B-3 Amine Sweetener incand a BETEX stripper.

Treatedgas

Rawgas

Absorber

To BTEX

Activatedcarbon filter

From BTEX

Flashgas

FIGURE B-4 Amine sweetening uCleaning process was thetime-limiting step.

32 h were spent cleaningthe severely fouledtubes before halting theprocess.

ludes a contactor, regenerator

Acidgas

Regenerator

Hot oil

nit.

DEAstoraganoth

The s

plant

by so

One anorm

The initial pnot allow caddition toan anadded

Proceconsi

isolation valves were toisolate the reboilers.

u

Stav

Reboile

Rhre

Appendix B: Judge Digby Gas Plant Hikes Production 173A Management of Change(MOC) document wasdeveloped and

Process Hazards Analysisreview was performed.

Considered all thechanges needed toaccommodate a solventswitch, includingspecial issues such as

Metallurgy

Equipmentconfiguration

Pump design and

Gasket materials

Review indicatedthat no additionalmodifications wererequired.

Training

Conducted for

Unit operatorsand

Companyengineers.tifoam charge pump was.

ss Safety Managementderationslids and

ntifoam used foral operations.

lant configuration didontinuous antifoamthe stripper; thus:

One antifoam used forstart-up that wouldprevent foaming createdTwo antifoams were brought to theand filled with an initialcharge of 45 wt% AP-814.was removed from thee tank and shipped toer plant.

torage tank was cleanedfouling.lvent was added to thenit.

olvent swap would haveken 4 h if the isolationalves did not leak.

r tube fouling

eboiler tubes wereydroblasted in an attempt tomove the iron carbonateIsolation valves leakedand reboilers had to becleaned before freshsoFocused on

New laboratorytest methods

Operatingtechniques and

Operatingparameters withthe new AP-814solvent.

Operations designed a timewindowfor the reboiler cleaning and solventchange-out.

The turnaround

In October 2000

DEA was removed from thesweetening unit and drainedfrom all the low points asmuch as possible.

Amine unit was flushed withwater drained.

Activated carbon filter wasemptied and filled with afresh charge.

After start-up, a gaschromatographic analysis indicatedthat only trace amounts of DEAremained in the system.

Solvent swap

Initially, inlet and outlet

After 32 h hydroblasting wasstopped and the reboilerwas put into service.

2030% of the tubesremained plugged with theiron carbonate.

Unit started up smoothly with thenew solvent.

Plant produced the expectedadditional 20 MMcfd of gas,even with the fouled reboilertubes.

Plant operations

Plant operated for 6 weeks whenwell production was lost.

Table B-3 shows performancedata collected during thattime.

Since the new solvent removedmore CO2, sweetened gas could bemixed with untreated gas.

New solvent allowed moreoperating flexibility, which helpedcompensate for less than optimumreboiler performance.

Damaged wells were restarted inMarch 2001.

Plant could not run at highrates because the reboilertube condition hadworsened.

Reboiler tube bundle wasreplaced.

Table B-4 shows the plantperformance with AP-814 andthe historical maximumperformance with DEA.

After bundle replacement

Plant had no problemmeeting design capacity.

At $3.00 Mcf1, thistranslates to an incrementalincrease in sales revenuesof approximately $34million/year.

a

)

Reboiler duty (MMbtu/h)CO2 in outlet gas (%)

ma

D

)

174 Gas Sweetening and Processing Field ManualTable B-4 Optimized perfor

Maximum processing capacity (MMcfd)Solvent circulation rate (gpm)Solvent CO2 loading (mol CO2/mol solventLeanRichReboiler duty (MMbtu/h)CO2 in treated gasOutlet from contactor (%)Sales gas with bypass (%)Table B-3 Operating perform

Inlet gas flow rate (MMcfd)Bypass gas flow rate (MMcfd)Gas flow rate to absorber (MMcfd)Inlet gas pressure (psig)Inlet gas temperature (F)Solvent circulation rate (gpm)Lean solvent loading (mol CO2/mol solventLean solvent temperature (F)nce with Ucarsol

1312610510011028400.03117480.01

nce comparison

EA (33 wt%) Ucarsol (45 wt%)

136 150953 1000

0.06 0.030.49 0.4650 50

2 0.20.53

Plant performance

OPEX remained the samewith the AP-814 despite thecapacity increase.

Amine unit could theoreticallyprocess up to 168 MMcfd ifother bottlenecks wereremoved.

Lab tests did not show anysolvent degradation.

Solvent losses were low.

Sweetening unit ran for

Betex emissions

Judge Digby gas stream containssome BETEX.

BETEX compounds have a high fuelvalue.

Regulated for human contact andair emissions.

BETEX is more soluble in aminesolvents than other hydrocarbons.

Plant has a BETEX-removal unit that

the BETEX, is recovered

Ref

Appendix B: Judge Digby Gas Plant Hikes Production 175performance from the5-mm filters confirm thisfinding.

Sweetening unit performedwell during upstream upsetsand well outages.reading low levels.

Low iron levels in thesolvent and goodhigh levels of corrosionwith DEA are nowDuring the change-out, the10-mm particulate filters werereplaced with 5-mm filters.

New 5-mm filters arechanged-out half asoften.

Corrosion is low.

Corrosion monitoringprobes that indicatedmonths without anysignificant change insolvent concentration.1. Hlozek, R., & Jackson, S. Louisiana

gas plant hikes production with

quick solvent changeout, Oil and

Gas Journal, June 9, 2003.significantly alter the load onthe BETEX-removal system.

erenceand routed to theplants fuel-gas system.

The BETX unit was evaluatedusing AP-814 solvent at ahigher circulation rate. Theevaluation indicated thechange from DEA did notstrips BETEX from the rich amine.

Unit is on the rich-amine linebetween the rich-amine filtersand lean-rich heat exchanger.

Fuel gas is the stripping agent.

This gas, along with anygas stripped out with

Judge Digby Gas Plant Hikes Production with Quick Solvent Change-Out1: Case StudyJudge digby plantDebottleneckingPreparing for the conversionThe turnaroundPlant operationsBetex emissions