SPE-169705-MS Colloidal Dispersion Gels (CDG): Field Projects
Review Manrique, E., Reyes, S., Romero, J., Aye, N., Kiani, M.,
North, W., Thomas, C., Kazempour, M., Izadi, M., Roostapour, A.,
Muniz, G., Cabrera, F., Lantz, M., Norman, C., TIORCO LLC Copyright
2014, Society of Petroleum Engineers This paper was prepared for
presentation at the SPE EOR Conference at Oil and Gas West Asia
held in Muscat, Oman, 31 March2 April 2014. This paper was selected
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Abstract
ColloidalDispersionGels(CDGs)havebeensuccessfullytestedinArgentina,China,USA,andrecentlyinColombia.
However, questions remain whether CDGs can be injected in large
volumes and propagate deep into the formation without reducing
injectivity and also improve sweep efficiency.
Thispapersummarizes31implementedandongoingCDGprojectsinArgentina,ColombiaandtheU.S.since2005.
Project summary review includes main reservoir properties,
operating conditions, pore volume of chemical injected, general
projectperformance,andespecially,adetailedanalysisofinjectionlogsaddressingtheinjectivityofCDG.Additionally,a
general approach for history matching CDG floods is described.
CDGinjectionvolumesinprojectsreviewedvaryfromafewthousandbarrelstohundredsofthousandsofbarrels.
Projectsevaluateddidnotshowinjectivityreductionevenaftermorethan600,000barrelsinjectedinonewell.Polymer
concentration and polymer:crosslinker ratios ranged from 250 to
1,200 ppm and 20:1 to 80:1, respectively. Aluminum citrate
isthemostcommoncrosslinkerusedinfieldprojects.However,chromiumtriacetatehasbeenusedinhighsalinityand
hardness conditions. Key variables to sustain the injection of
large volumes of CDG below maximum operating pressure are
polymer:crosslinkerratios,polymerconcentration,andinjectionratestoalesserextent.CDGprojectshaveevolvedfrom
smalltolargetreatmentvolumesshowingapositiveimpactonoilrecoveries.DespitelargevolumesofCDGinjected
productionofpolymerinoffsetproducershasrarelybeendetected.Wellheadpressureresponse,CDGviscosity,and
adsorption/retention (RRF) represents the most important variables
needed to match CDG floods. This study provides the status of the
technology and field evidence that CDGs can be injected in large
volumes and can propagate into the reservoir without injectivity
constraints. This review will also provide guidance to successfully
design and evaluate CDG pilot projects. Lessons learned from
operating and modeling CDG projects will also be presented.
Introduction
Theconceptofreservoirpermeabilitycorrectionusingsequentialinjectionofpolymersandmultivalentmetalions
solutions(i.e.,AluminumCitrate-AlCit)wasoriginallypatentedbyGall(1973).TheResidualResistanceFactor(RRF)
generatedbythismethodwasclaimedtobegreaterthantheRRFproducedbytheinjectionofpolymeronly.In1980a
commercialscaleapplicationofthetechnologywasreportedintheNorthBurbankUnit(NBU),Oklahoma(Moffittetal.
1993). Applications at NBU evaluated different strategies including
the sequential injection of polyacrylamide solutions and
crosslinkingsolutions(AlCitorChromiumPropionate).Incrementalcostperbarrelreportedintheseprojectsrangedfrom
$US 12 to $US 14. Lower cost per incremental barrel was reported
using chromium triacetate as a crosslinker. However, the reduction
in costs was mainly attributed to the use of produced brine rather
than fresh water as injection fluid.
Inthemid-1980s,theco-injectionofpolymersandcrosslinkerswasintroducedtotheindustryandwasreferredasin-depth
colloidal dispersion gels (CDGs).The co-injection of the polymer
and crosslinker solutions simplified operations and allowed
theinjection of larger volumes of chemicals.Mack and Smith (1994)
reported asummary of 29 CDGprojects (19 successful, 3 marginally
economic and 7 unsuccessful) in the Rocky Mountain area.CDG
technology generated attention in 2SPE 169705 China (Zhidong et al.
2011), other regions in the U.S. (Manrique and Lantz, 2011) and
more recently in Argentina (Diaz et al.
2008;Muruagaetal.2008;Menconietal.2013)andColombia(MayaandCastro2013;Castroetal.2013).However,
despitenumeroussuccessfulfieldresultsreportedintheliterature,laboratory-scaleexperiments(Al-Assietal.2006;
Ranganathan et al. 1998; Seright 1994and 2013)havegenerated
controversyregarding theability to injectCDGsinlarge volumes
without reducing injectivity while also improving sweep efficiency.
Spildo et al. (2009 and 2010) demonstrated that CDG aged a few days
could propagate through Berea cores and increase
oilrecoveryatirreducibleoilsaturationtowater.Castroetal.(2013)recentlyvalidatedthatCDG(AluminumCitrateand
HPAM) freshlymade or aged for one week can propagate in Berea core
plugs.Additional results of this study showed that incremental oil
recoveries were higher and differential pressures were lower when
injecting freshly-made CDG compared to one-week-aged CDG. Figure 1
depicts polymer and aluminum concentration recovery (at irreducible
oil saturation to water or Sorw) in the Berea core floods reported
by Castro et al. (2013). Injected CDG was prepared in synthetic
formation brine (1% total salinity) using 600 ppm of polymer (HPAM)
and a polymer:crosslinker ratio of 20:1 as reported by Spildo et
al. (2010). Elution of polymer and aluminum in the experiment
injecting freshly-made CDG (Fig. 1a) shows clear differences with
one-week-agedCDG(Fig.1b).Thedatashowthatpolymerandaluminumareproducedataconstantratioafterinjecting
approximately3.5PVoffreshlymadeCDGatdifferentinjectionrates(Fig1a).However,fortheone-week-oldCDG,
polymer and aluminum are produced at a constant ratio after
approximately 1 PV injected (Fig. 1b). This result was expected
duetotheinjectionofpre-formedCDG(polymerandaluminumalreadycross-linkedbeforeitsinjection).Theseresults
validate that CDG can propagate in the porous media as reported by
Spildo et al. (2010) and provides additional evidence to support
the feasibility of injecting large volumes of CDG without well
injectivity constraints. Figure 1. Concentration of polymer and
aluminum as a function of produced PV during oil recovery
corefloods (@ Sorw) using CDG freshly made (a) and aged for one
week (b)
DespitetheexistingdebateregardingtheeffectivenessofapplyingCDGorweakgelsforconformanceormobility
control purposes, the number of laboratory and fields studies
continues to increase demonstrating the interest of this topic due
toitssignificanceforincreasingoilrecoveryinwaterfloodprojects.Mumallah(1987)suggestedthattoachievein-depth
permeabilitycorrection,dilutepolymersolutionsandcrosslinker(gellingagent)shouldbeinjectedinoneslugorina
sequentialmode(polymer-crosslinker-polymer)allowingtheweakgelstoformin-situandpartiallyblockingtheinvaded
zone.Mumallahalsostatedthatin-depthpermeabilitycorrectionoperationsarepreferredoverpolymerfloodonlyornear-well
gel treatments because a large portion of the reservoir can be
treated at a reasonable cost and the permeability reduction
lastsforsometime.Theconceptofin-depthprofilemodificationtoimprovewaterfloodsweepefficienciescontinuesto
evolvefromDeepDivertingGelsorDDG(Fletcheretal.1992)totheconceptofThermallyActivePolymers(TAP)also
known as BrightWater (Frampton et al. 2004; Pritchett et al. 2003;
Salehi et al. 2012). In 2003 the application of weak gels
forin-depthprofilemodificationandoildisplacementwasreportedbyWangandLiu(2003).Shietal.(2011)reporteda
detailedliteraturereviewonvariousmicrogelmethodsincludingamodelingapproachforCDG.Zhidongetal.(2011)
providedacomprehensivecomparisonofCDGandpolymerfloodingprojectsimplementedintheDaqingFieldinChina.
Morerecently,acomparisonbetweenpolymerfloodingandin-depthprofilemodificationusinganalyticalandnumerical
methods was presented by Seright et al. (2012). It is important to
remark that one of the main motivations of in-depth injection
profile modification since its early stages of development (Gall
1973; Frampton et al. 2004) was thepotential limitation ofsevere
injectivity reductionusing polymer flooding or conventional polymer
gels (i.e., MARCITsm gels). Injectivity losses are not only
associated to the potential risk of losing oil production (poor
voidage replacement) but also can be limited by injection
capabilities of existing surface facilities.
Therefore,theinjectionofviscouspolymersolutionscouldbelimitedinsomescenarios.Tomitigateinjectivitylossesthe
SPE 1697053 injection of polymer solutions above fracture gradients
has been proposed and implemented in the field. However, injection
abovepartingpressureisnotnecessarilythebestoperatingstrategyforchemicalfloodsandcanleadtoearlychemical
breakthrough increasingoperating expenditures (OPEX) due
toincreased crude oil-chemical separation and water treatment for
re-use or disposal. Additionally, high polymer production can also
lead to productivity losses not commonly documented in the
literature (Singhal 2011; Choudhuri, et al. 2013) and that will
impact project economics.
Fortheabovereasons,CDGhasbeenconsideredasafeasibletechnologyforin-depthconformanceandasamobility
control strategy to improve oil recovery and reduce water
production in waterflood projects. In addition to project
economics,
someofthevariablesfrequentlyconsideredforevaluationofCDGtechnologyoverstraightpolymerfloodingornear
wellbore treatments with conventional polymer gelsnormallyinclude
one ormore ofthe following conditions and possibly others,
depending on the reservoir: Maturity of the waterflood (Evaluate
evidence for presence of remaining movable oil) Waterfloods
operating under adverse mobility ratios Low reservoir permeability
Thin reservoirs (Net pay thickness < 40 ft) injecting water with
vertical wells Potential injectivity constraints due to narrow
margin between maximum injection and reservoir pressures (Assumes
injection below parting pressure) Limited water handling
capabilities Requirement to minimize or delay polymer production
This paper will summarize 31 implemented and ongoing CDG projects
in Argentina, Colombia, and the U.S. since 2005. The project
summary review includes main reservoir properties, operating
conditions, pore volume of chemical injected and
generalprojectperformance.Wefocusontheanalysisandpossibleinterpretationofinjectionlogs(i.e.,plotsofinjection
parameters) as an attempt to provide evidence regarding the
injectivityand propagation of CDG. Injection log interpretation
will also include theuse of Hall plots comparing CDG vs. polymer
injection and different conformance technologies (TAP, CDG, and
MARCITsm gels). A special case including wells with CDG
re-treatments will be also presented. Finally, a general approach
for the prediction and history matching of CDG floods is also
described. CDG Project Reviews Table 1 shows a summary of the main
reservoir and operating conditions of the CDG projects reviewed.
Projects include
theuseofCDGtechnologyforin-depthconformance,mobilitycontrolorboth.Athirdgroupconsideredtheinjectionof
polymergelstoreducewaterchannelingfollowedbyCDGasamobilitycontrol(Menconi,etal.2013;Muruaga,etal.
2008). Table 1Summary of reservoir and operating conditions of CDG
projects reviewed Basic Reservoir PropertiesRange Temperature (F)80
- 210 Permeability (mD)10 - 4,200 Average Net Pay (ft)20 - 200 Oil
Viscosity (cP)5 - 30 Pressure at Start (psi)0 - 1,400 Basic
Operating Parameters Polymer Conc. (ppm)250 - 1,200 Crosslinker
Aluminum Citrate (23 of 31) Chromium Acetate (8 of 31)
Polymer:Crosslinker Ratio20:1 to 80:1 Injection rates (bbl/d)150 -
2,000 Maximum Operating Pressure (psi)750 - 2,200 Volume Injected
(bbls/well)10,000 - > 650,000 Use of CDGs as an in-depth
conformance or mobility control strategy depends on multiple
variables. Adverse mobility,
narrowmarginofmaximuminjectionandreservoirpressures,andhighwatercutswerecommonfactorsintheprojects
reviewed.Additionally,someoftheprojectsincludedevaluationoftheinjectionofbulkpolymergels(MARCITsmgels)
beforestartinginjectionofCDGs.However,insomeoftheprojects,bulkpolymergelsgeneratedmarginalresultsdueto
low injectivity (wells pressured-up too fast) leading to small
volume treatments that generated results below expectations.
Fig.2depictsinjectionlogsofthe31CDGprojectsevaluated.CDGprojectsreviewedaremainlyforin-depth
conformance and an ongoing mobility control project represented by
theonly well reporting more than 650,000 bbl injected (Castro et
al., 2013). None of the projects showed prolonged continuous
increase in injection pressures. 4SPE 169705 Fig. 2CDG injection
logs (wellhead injection pressure vs. Cum. CDG injected) of 31
projects reviewed
OncethetechnicalandeconomicfeasibilityofCDGisvalidatedapilotinjectionschemeisproposedincluding
contingency plans to address possible unexpected situations at
injectors (e.g., sharp increases in pressure) or producers (e. g.,
polymer production). Before project startup, injection profiles
(i.e., ILT) are usually available to indicate the location and the
waterintakeofdifferentperforatedintervals.TopromoteCDGflowthroughhighflow-capacityzones,injectionratesare
reduced if required. This will also reduce the risks of injecting
higher viscosity fluids above frac gradient. If the reduction of
injectionrateimpactsoilproductionratesinoffsetproducers,thenthisisalsoincludedintheevaluationtominimize
productionlossesduringthetreatmentthatcanimpactprojecteconomics.Definingmaximumoperatingconditionsalso
represents a key operating variable before CDG injection is
started. Maximum operating pressure could be limited by surface
facilitiesorformationpartingpressureandwillcontributetomodifyingthetreatmentbyadjustingkeyoperatingvariables
such as polymer concentration, polymer:crosslinker ratios, and/or
injection rates. For the purpose of this analysis CDG conformance
projects were divided into two groups, (a) wells starting with
positive
wellheadpressure,and(b)wellsstartingundervacuum.Typically,forthetreatmentsstartingwithpositiveinjection
pressure,pressurebuildupresponsewasobservedafterafewhundredto20,000bblsofCDGinjected.Onceinjection
pressureisapproachingmaximumoperatingconditions,polymerconcentrationand/orpolymer:crosslinkerratiosand
injectionrates(toalesserextent),aretypicallyadjustedaccordinglytocontinueinjectingclosetomaximumoperating
conditions.
TofurtheraddresstheinjectivityofCDG,aprojectimplementedinathin(20to25ftthick)andrelativelylow
permeability (1.8 to 600 md) reservoir in the U.S.was selected for
amore detailed discussion.CDG was considered in this
fieldduetofasttracerbreakthrough(5to30days)infourinjectorswith5-acrewellspacinginirregularpatterns.To
minimize the risk of polymer production, all injectors were treated
with approximately 1,000 bbls ofMARCITsm gels before
CDGinjectionstarted.Averagepermeabilityofthisreservoirwasestimatedtobe300md.Theoilviscositywas8cpat
reservoir conditions. After completing theMARCITsm gel treatment,
CDG injection started with a polymer concentration of
600ppmandapolymer:crosslinkerratioof30:1.Atprojectstartupthereservoirpressurewas250psiandthemaximum
operatingconditionwasdefinedas750psi.Afterapproximately10,000bblsofCDGhadbeeninjectedineachwell,all
injectors reached an injection pressure of 600 psi.At this point
polymer concentration was decreased to 450 ppm keeping the same
polymer:crosslinker ratio (Fig. 3). Pressure continued to increase
and polymer concentrationwas reduced to 300 ppm
untiltheendofthetreatmentwithoutmodifyingpolymer:crosslinkerratioorinjectionrates(200to220bbl/d/well).The
volumeofCDGinjectedrangedfrom16,000to18,000bblsperwellrepresentingapproximately4%ofthepilotpore
volume. Fig. 3shows theinjectionlogsfor theCDGinjection infourwells
after theinjection of 1,000 bbls/each ofMARCITsm
gels.ResultsclearlysuggestthatCDGcouldbeinjectedwithoutfacepluggingasreportedinsomelaboratorystudies(Al-Assi
et al. 2006; Ranganathan et al. 1998; Seright 1994). This example
will also be addressed in the CDG simulation section SPE 1697055
explainingtheuseofthegeloptiontohistorymatchpressurebuildupobservedinthefield.Itcanbenoticedthatpressure
buildupobservedinallfourwellsshowsasimilarpatternandareasonablefitcanbeobtainedwithaconventional
polynomialequationof2ndorder(Fig.3a).Tofilternoiseinthedatagatheredforeachoftheinjectors,thedatasetswere
smoothedusingLoess(quadraticfit)methodpriortothecurvefittingprocess.ItwasfoundthatdifferentformsofPower
functionsfitthedataquitewell(Fig.3b).Interestingly,similartrendswerefoundinmorethan80%ofthefieldcases
analyzed providing useful information regarding possible gel
formation and its propagation in the porous media. Fig. 3CDG
injection logs implemented in a thin and low permeable reservoir in
the U.S.
Fig.4showswellinjectivityforallCDGprojectsevaluatedinthisstudy.MostwellstreatedwithCDGdidnotshow
injectivityreductionexceptforthosetreatmentsstartingaftertheinjectionofMARCITsmpolymergels(highlightedinFig.
4),whichwereappliedduetoearlytracerbreakthroughand/orwellinjectingwaterundervacuum.Onegoodexampleof
combiningMARCITsmgelsfollowedbyCDGinjectionhasbeenreportedbyMuruagaetal.(2008)andMenconietal.
(2013). Combination of MARCITsm gel injection is not only limited
to CDG; Saez et al. (2012) and Paponi et al. (2013) have recently
reported on projects combining MARCITsm gels followed with polymer
injection to solve severe water channeling in a viscous oil
reservoir in Argentina. Fig. 4Well injectivity for CDG projects
evaluated The Hall plot represents another tool to monitor project
performance of conformance treatment and EOR floods. The Hall
plotwasoriginallyproposedtoevaluatetheperformanceofwaterfloodsandestimateskineffectsinwaterinjectionwells
(Hall1963).Buelletal.(1990)proposedamethodtouseHallplotsforbothwaterandpolymerfloods(Non-Newtonian
fluids).HonarpourandTomutsa(1990)alsoproposedtheuseofHallplotsformonitoringandreservoircharacterization
purposes in Bell Creek water and micellar-polymer flood. Hall plots
of in-depth conformance technologies (i.e., CDGs and 6SPE 169705
TAPs)generallyshowagradualincreaseofpositiveskincomparedtonearwellboretreatmentssuchasMARCITsmgels,
which show a sharper increase of positive skin. CDG treatments can
also show a sharp increase in Hall plots when injected at
highpolymerconcentrationswithpolymer:crosslinkerratiosbetween20:1to40:1.However,thisbehaviorshouldbe
considered well specific and cannot be generalized as a rule. In an
attempt to compare Hall plot differences between conformance
technologies, projectswere selected that had similar
injectionrates(1,000bbl/d)injecting(1)MARCITsmgels,(2)CDG,and(3)TAPtechnologies(Fig.5).TheHallplot
comparisons in Fig 5 are for the first few thousands of barrels
injected for each treatment.MARCITsmgelwas injected at a
concentration of 4,500 ppm (Black dashed line) and all TAP
(BrightWater) projects were pumped using a concentration of
5,000ppm.HallplotsfortheCDGprojectsshowninFig.5fellinbetweenTAPandMARCITsmgels.CDGtreatment1
(Greendashedline)wasinjectedusingapolymerconcentrationof600ppmandpolymer:crosslinkerratioof20:1.CDG
treatment 2 (Red dashed line) was implemented using a polymer
concentration of 300 ppm and a polymer:crosslinker ratio of
40:1.AlthoughcomparingHallplotsofdifferentprojectsandtechnologiesinvariousfieldsischallenging,thisexample
presents a general idea of the injection performance of different
conformance technologies. As expected, TAP Hall plots do not show
major changes during TAP injection due to the low initial viscosity
at these concentrations for this polymer system
andlowertemperaturesusuallyobservedinwaterinjectionwells.OnceTAPisactivatedtheHallplotwillshowagradual
increaseofpositiveskin(Choudharyetal.2014).CDGprojectsconsideredforcomparisonpurposes(Fig.5)showarapid
positive skin due to the viscosity of the systems injected as a
conformance strategy and low reservoir permeabilities. Fig.
5Example of Hall plots for two CDG projects evaluated compared with
different conformance technologies El Tordillo Field (Argentina)
represents one of the fields with the largest number of CDG
treatments (11 wells).Reported
incrementaloilrecoveriesarebetween3and3.5%oftheOOIP(Menconietal.2013).However,CDGinjectionwas
combined with MARCITsm gel treatments to control severewater
channeling through high permeability channels present in
thereservoir.Again,thecombinationofMARCITsmgelsbeforeCDGinthesetreatmentsdidnotgenerateinjectivity
constraintsorfacepluggingasreportedinlaboratorystudies(Al-Assietal.2006;Ranganathanetal.1998;Seright1994).
Theoperatoriscontinuingtousethetechnologyandimprovingitsimplementationbasedonlessonslearnedanddetailed
reservoir management strategies to develop the field.
DaqingfieldinChina(Changetal.2004;Zhidongetal.2011)andmorerecentlyDinaCretceosfieldinColombia
(Castroetal.2013)aretheprojectswiththelargestCDGinjectedvolumesperwelldocumentedintheliterature.Daqing
fieldexperienceshavebeenwidelydocumentedintheliteraturebutfieldinformationanddetailedperformancearenot
available. However, recent comparison of CDG vs. polymer flooding
was summarized by Zhidong et al. (2011). In the case
ofDinaCretceosfield,thepilotstartedin2011.Over650,000bblsofCDGhadbeeninjectedinthefirstpilotinjector
withoutmajorinjectivityproblems.BasedonCDGoilproductionresponseandwatercutreductionthepilothasbeen
expanded by increasing the number of injectors as reported by
Castro et al. (2013). Considering the fact that there are not many
fields (other than Daqing) reporting CDG and polymer flooding in
the same reservoir, this paper compared a few ongoing polymer and
CDG floods implemented in low permeability reservoirs (5 to 300
md)wherethe dataisavailable.Hallplotswereagainused to
demonstratetheinjectivity of largevolumes of polymer and CDG in
reservoirs with reasonable similarities (Fig. 6). The polymer
projects are injecting above the frac gradient (1,500 to SPE
1697057
3,000bbl/d)usingpolymerconcentrationsbetween500and800ppmwhileCDGprojectsareinjectingbelowthefrac
gradient (1,000 to 2,000 bbl/d) with polymer concentration between
300 and 600 ppm and variable polymer:crosslinker ratios
(40:1to80:1).Hallplotsofpolymerinjection(dashedlinesinFig.6)clearlyshowtheeffects(periodsofskindecrease)
generatedbyinjectionratechangestokeepinjectingabovefracgradientinalowpermeabilityreservoir.TheHallplotof
CDG injection (solid lines in Fig. 6) are comparable to polymer
floods considering that injection rates are belowthe fracture
gradient and the main operating variable to keep injecting high
volumes below or close to the maximum operating conditions is the
variation of polymer:crosslinker ratios and polymer concentration
or injection rates to a lesser extent. Fig 6Example of Hall plots
comparing CDG vs. Polymer injection in reservoirs with similar
characteristics
PolymerandCDGprojectsshowninFig.6areperformingaboveexpectationsusingdifferentoperatingstrategies.As
stated earlier, comparing Hall plots of polymer based technologies
in different fields is challenging but it is clear that CDG can be
injected in largevolumes without reducing injectivityand
propagating through the reservoir despite somelaboratory
studiesconcludingtheopposite.TheHallplotpresentedinFig.6cannotexplainthekineticsofformationorflow
characteristicsofCDGinthereservoir.However,theCDGprojectsareshowingincrementaloil,decreaseinwater
productionwithoutpolymerproductionatacostbelow$US5perincrementalbarrel.Therefore,thereisadiscrepancy
between laboratory and field evidence that needs to be re-addressed
because evidence from field projects show low cost per
incrementalbarrel,decreaseinwaterproductionandnoevidencesofpolymerproductionorinjectivity/productivitylosses.
The following sections will continue presenting additional evidence
that CDG can be formed and propagated in the reservoir without
causing well plugging. Special Case: Wells with CDG Re-treatments
Well retreatment for in-depth profile modification has been
proposed as a possible strategy to improve sweep efficiency in
water injection projects (Choudhary et al. 2014). Fundamentally,
the objective of a second (or additional) treatments (i.e.,
re-treatments)istopreventordelaywaterchannelingofsecondarythiefzonestocontinueimprovingvolumetricsweep
efficiencyandhenceincreasingoilrecovery.Thefirsttreatmentwillpartiallyblockhigherflow-capacityintervalsand
subsequenttreatmentsmaytargetlesspermeable(lowerflowcapacity)intervalsand/orexpandtransmissibilityreduction
generated by the first treatment. This concept was recently
evaluated using a numerical simulation approach by Seright et al.
(2012). Well re-treatments with CDG have been also reported by Diaz
et al. (2008) and Castro et al. (2013). Fig. 7 depicts two wells
reporting CDG re-treatments. Subsequent CDG slugs were injected
after several months of water
injectionatthesameinjectionrates.ThewaterinjectiondataarenotshowninFig.7.Fromtheinjectionlogsitcanbe
concludedthatthere-treatmentswithCDGdidnotshowinjectivityconstraints,whichsupportstheconclusionthatface
plugging of the injectors was not occurring. CDG Re-Treatment 1
(Fig. 7) consisted of the co-injection of a polymer solution
of400ppmandvariablepolymer:crosslinkerratiosusingAlCitasacrosslinker.CDGRe-Treatment2(Fig.7)co-injected
polymer andChromium Triacetate as acrosslinker.CDGRe-Treatment
2caseconsidereddifferentpolymer concentrations (300 to 450 ppm) and
polymer:crosslinker ratio (20:1 to 40:1). An interesting
observation of both projects is that oil response
wasobservedduringthefirsttreatmentvalidatingthepossibilityofCDGdisplacingviscousoilsasreportedbyDiazetal.
8SPE 169705 (2008) and Castro et al. (2013). CDG Re-Treatment 2
(Case 2) was selected to provide additional evidences that CDG can
be formed and propagate in the reservoir. Fig. 7Examples of
injection logs for wells reporting retreatment with CDG
ComparingbothCDGinjectiontreatments(attimezero)ofCase2itcanbeobservedthatbuild-uppressuresarevery
similar (Fig. 8). It is important to observe that each CDG
phase(Phase I and Phase II) injected approximately 190,000 bbls
(Fig. 7). CDG injected during Phase I of the project involved a
variable polymer concentration (300 to 450 ppm) at a constant
polymer:crosslinker ratio of 20:1. The second CDG treatment (Phase
II) was implemented after 13 months of water injection at an
approximately constant injection rate of 1,076 bbl/d. Injection
strategy for Phase II of the project considered a different
strategyinjectingataconstantpolymerconcentrationandpolymer:crosslinkerratioof300ppmand40:1,respectively.
SimilaritiesofbothCDGtreatmentinjectionlogs(Fig.8a)suggeststhatthefirsttreatment(PhaseI)didnotchangewell
injectivity and thesecond treatment(Phase
II)isflowingthroughthesamehigh permeableinterval (i.e., the first
treatment might be too small to generate a stronger water
diversion) and/or CDG formation (chemical reaction) occurs at a
given rate in
thereservoir,amongotherpossibilities.Aswasobservedinthefourfieldcasesdescribedatthebeginningofthissection
(Fig.3a),pressurebuild-upduringthefirst20,000bblsofCDGinjectedisverysimilarandcanbefittedwithasimilar
polynomial of 2nd order (Fig. 8b). This pattern (pressure buildup
type curve) has been observed in more than 80% of the field
casesevaluatedandmayprovideimportantinformationregardingtheCDG(microgel)formationandcharacteristicsofits
propagationinthereservoir.However,additionalinterpretationsarerequiredtoinferpossiblegelformationsupportedby
numerical simulation studies. Fig. 8Comparison of injection logs of
CDG re-treatments of Case 2 shown in Fig. 7 for the total treatment
of each phase (a) and pressure build-up observed during the first
20,000 bbls of CDG injected (b) SPE 1697059
Basedonlaboratorystudies,CDGscannotbeformedinthereservoirorshouldpluginjectorsbecauseitcannot
propagate in the reservoir. CDG re-treatments presented in this
section do not support a conclusion that face plugging of the
injectorsoccurred.However,thesefieldcasesdonotnecessarilyvalidatetheformationofCDGinthereservoir.TheHall
plot was used to continue evaluating CDG performance of Case 2
(Fig. 9). The Hall plot includes the injection history since the
injector started with water injection, which identified some well
events (changes in injection rates) and the periods when both CDG
treatments were implemented. Fig. 9Hall Plot of CDG retreatments of
case 2 shown in Figs. 7 and 8
ThefirstCDGtreatmentof186,200bblswasinjectedat1,025bbd/d.DuringtheCDGinjection,anincreaseinoil
production and a decrease in water production were observed. The
operator ran an injection profile (ILT) before and after the
firstCDGslug.TheinjectionprofileafterthefirstphaseofCDGinjectionshowedaclearreductionofwaterintakeinthe
main thief zone and new intervals taking injection water that did
not record any injectivity prior to CDG injection (Diaz et al.,
2008). Water injection rates were kept constant at 1,076 bbl/d
after Phase I of the CDG project. It can be noticed that the Hall
plot shows aslight increase in positiveskin typical of in-depth
conformance (Choudhary et al., 2014) compared with water
injectionatasimilarinjectionrate.BasedonthetrendsobservedintheHallplot(Fig.9)andchangesininjectionprofiles
observedrightafterthefirsttreatment,itcanbeconcludedthatCDGformedandwasdisplacedawayfromtheinjector
having a small influence near the injector wellbore. Additionally,
a slight and continued increase in positive skin (Trend I in
Fig.9)andnopolymerproductioninoffsetproducersalsosuggestthatin-depthpermeabilityreductionwasstillinplace
before phase II of the CDG project started. After approximately 13
months injecting water, Phase II of the project started with a
slightly lower injection rate (1,002 bbl/d). The second CDG slug
(192,729 bbls) was injected without any injectivity constraint,
which can be confirmed with the
overlapofpressurebuild-upresponseofbothCDGtreatmentsdescribedinFig.8.However,fivemonthsafterthesecond
phase of CDG injection was completed, injection rateswere decreased
(700 bbl/d) due to the increase of wellhead injection pressures
caused by water diversion to lower permeability intervals and
continued water injection below the parting pressure. Injectivity
reduction should be expected due to water diversion into low
flow-capacity (unswept) zones. A sharper increase in positive skin
(Trend II in Fig. 9) and no polymer production in offset
producerssuggest that in-depth permeability reduction occurred. It
can be argued that a decrease in water injection rates may have a
negative impact on oil production rates (voidage ratio) of the
pattern treated twice with CDG. However, project economics needs to
take into account the benefits of CDG for
extendingoilproductionlifeofwaterfloodsbyreducingwaterre-cyclingandcontributingtoanincreaseinfinalrecovery
factors.
PressurebuildupandHallplotdatastronglysuggestthatco-injectedpolymerandcrosslinkerdoreactinthereservoir.
Case2representsagoodexampleofCDGformationanditspropagationinalowpermeabilityreservoir(20to1,000md)
with viscous oil (30 cp) at reservoir temperature of 113F (Diaz et
al. 2008). Injected polymer solution at low concentrations (300 to
450 ppm)in poorwater quality cannot justifythebuild-up
pressuresrecorded or increasein positiveskin observed during the
project (Figs. 8 and 9). Additionally, tracer breakthrough in two
of the six producers was reported between 50 and 10SPE 169705 110
days. However, no polymer production was reported during
theduration of the project. These field case histories clearly
contradictlaboratorystudiespostulatingthatCDGscannotbeformedorpropagateinthereservoir(Al-Assietal.2006;
PRRC 2013; Ranganathan et al. 1998; Seright 1994 and 2013).
Theauthors understand the difficultyof
demonstratinghowchemicalreactionsformingCDGoccur in thereservoir
but
thisdifficultyisnotdifferentthanotherchemicalEORprocesses.Onepossibleexplanationisthedifferencesinscale
betweencorefloodsandreservoirvolumesmakingitdifficulttocapturepossibleinteractionsatlaboratoryscale.For
example,viscositybuildupobservedinbottletestsisnotrepresentativefornumericalsimulationstudies.CDGviscosities
generatedinbottletestsareextremelyhighcomparedtothosemeasuredattheoutletofcorefloodorsandpacks.This
observationsuggeststhatchemicalinteractionbetweenthepolymerandthecrosslinkerintheporousmediadiffersfrom
bottletestobservationwhereallthereactantscaninteractwithoutconstraints.Thepressurebuild-upsignature(i.e.,type
curve)observedmaycontributetounderstandingthereactionmechanismsatreservoirconditions.Inthemeantime,CDG
kinetics has been investigated during history matching of recent
CDG floods. These observations will be briefly discussed in the
following section of the paper. CDG Simulation The use of numerical
simulation to potentially explain the observed characteristics of
in-depth conformance technologies
hasbeenreportedbyGarmehetal.(2012),GarmehandManrique(2011),Serightetal.(2012)andShietal.(2011).
Proposedtreatmentmethodsincludethermallyactivepolymers(i.e.,BrightWater)orchemical(i.e.,CDG,microgels)in-depthconformancetechnologies.CDGsconsistsofacross-linkedlowconcentrationpolymerthatdevelopsviscosityand
resistance factor with time during flow in the reservoir. To model
delayed viscosification (observed in the injection logs for
thecases reviewed)and adsorption ofthissystem,two approaches
havebeenevaluated: theuseofmultipleregions(single component) and
gelation (chemical reaction).
Notallcommercialsimulatorsincludechemicalreactionstoformgels.Therefore,areasonablysimplesimulation
approachwhereCDGismodeledasasinglecomponenthasbeenconsidered.Thisapproachtakesadvantageofdefining
multiple regions with increasing CDG viscosity and RRF moving away
from the injector. The intention of this method is to capture the
delayed viscosification of CDG deep in theformation, which can be
inferred from pressure buildup observed at
theinjectors.Althoughthisapproachissimpleandhasfasterrunningtimesasaresultofnothavingtodefinechemical
reactions in highly detailed numerical models, this method might
cause some numerical difficulties due to sudden changes in
fluidpropertiesfromoneregiontotheother.Tomakethistransitionsmoothermultipleregionsmustbedefinedwhich
represents a disadvantage of this approach. However, this method
can be used as a preliminary approachfor projects without access to
numerical tools including gel (chemical reaction) options.
Thesecond modeling approach is based onachemicalreaction to form
CDG. Inthis approach polymer and crosslinker
areinjectedinthereservoirwithspecificconcentrationsasithappensinfieldoperations.Eachcomponent(polymerand
crosslinker)isinjectedatagivenconcentrationandviscosity(initiallyalowerviscositythanCDGasdeterminedinthe
laboratory) and will react to form CDG considering the following:
CDG activation can be controlled by the reaction rate coefficient
Reaction product (CDG) will have high viscosity and resistance
against flow (RRF) due to adsorption/retention Chemical reaction
rate is tuned to build the viscosity vs. time curve (delayed
viscosification) Chemical reaction rate coefficient controls the
viscosification timing of CDG While the chemical reaction approach
provides a smooth transition in terms of CDG formation, reaction
stoichiometry is not well understood. In this approach
polymer:crosslinker ratio has a significant effecton the simulation
results and in cases when this ratio is changed (i.e., most common
variable changed in field operations) all other parameters have to
be adjusted
accordingly,whichmakesthisapproachrelativelycomplicated.Toovercomethispotentialcomplicationtheuseofatwo
component system has also been tested. In this case a chemical
reaction is defined toconvert CDG1 to CDG2 where CDG1 has lower
viscosity and RRF compared to CDG2. However, additional efforts are
required to improve the prediction of CDG during pilot design
phases. Fig. 10 depicts an example of CDG history matching using
the two different simulation approaches. The best approach to
history matching CDG performance is using pressure buildup reported
at the (four) injectors as describedpreviously in this
paper(Fig.3andFig.7).Fig.10arepresentsanexampleusingthesimulationapproachofmultipleregions.Bothmodels
(CDGModel 1 and CDG Model2)includethree regions.Themain difference
betweenbothmodels isthe approachto the viscosity build-up and RRF
from one region to the other. This simulation approach was also
compared with straight polymer
injection(GreendashedlineinFig.10a).Polymerinjectionwasbasedonthepolymerconcentration(400ppm)injected
SPE 16970511 during theCDG project inthe absence of crosslinker.
Results suggest that pressure build-up observed at the injector
cannot be matched using low polymer concentrations.
Thesecondhistorymatchedprojectwasbasedonavariablepolymerconcentration(300to600ppm)ataconstant
polymer:crosslinker ratio (30:1) as was described in Fig. 3. In
this case chemical reaction (gelation) approach was used and
reportedbyGarmehandManrique(2011).Thisgeloptionreasonablymatched(RedlineinFig.10b)historicalwellhead
pressuredata(BluecirclesinFig.10b)recordedduringthepilottest.Similarresultswereobtainedforallfourinjectors.
Again, this model was used to compare CDG vs. straight polymer
flooding. CDG injection started at 600 ppm and to history
matchhistoricalwellheadpressuredatapolymerfloodingwasassumedasinjectingthesamevolumeofCDGusinga
constantpolymersolutionof600
ppm.Again,resultssuggestthatpressurebuild-upgeneratedbyCDGcannotbematched
with straight polymer injection (Green dashed line in Fig. 10b).
Fig. 10Example CDG simulation approaches using multiple regions (a)
and chemical reaction (b)
TohistorymatchwellheadpressuredatadepictedinFig.10btheuseofvariableskinfactorswasalsoconsidered
(assuming face plugging effects).However, this approach could not
match injection or production rates during and after the injection
of CDG. Finally, a special case of polymer flooding was run to be
able to match incremental oil recoveries gained
bytheCDGpilottest.InthiscaseCDGandpolymerfloodinggeneratedsimilarincrementaloilrecoveries.However,
polymer flooding required approximately 16,000 pounds of additional
polymer mass compared to CDG. CDG injection used 875
poundsofcrosslinker,whichrepresentsimportantsavingsthatcanbenefitprojecteconomicsofthisparticularproject.
Therefore, itcouldbesuggested thatCDGisnot superior to
polymerflooding based onthesesimulation results. However,
projecteconomicswillprovideabenefitfromCDGwhencomparingtostraightpolymerflooding.Additionalbenefitsof
CDGarethatfieldprojectexperiencehasshownthatlesspolymerwillbeproducedcomparedtopolymerflooding,which
reduces treatment costs of produced fluids. In other words, CDG can
generate similar recoveries at lower CAPEX and OPEX.
However,itisimportanttomentionthatCDGcannotbeformedundercertainreservoirconditions.Finally,theauthors
recognize that a comprehensive review of laboratory protocols needs
to be revisited to better explain field observations. Discussions
and Closing Remarks
Injectionlogs,wellinjectivity,andHallplotsconfirmthatCDGsdonotsignificantlyreduceinjectivityandcan
propagate in the reservoir.
FieldcasesreviewedshowedthatlargevolumesofCDGcanbeinjectedbelowmaximumpressureoperating
conditions(i.e.,belowthefracturegradientormaximumcapacityofsurfacefacilities).Themainvariablesto
managetheinjectionoflargevolumesofCDGincludepolymer:crosslinkerratios,polymerconcentration,and
injection rates in a lesser extent. The pressure responses that
have been observed in different wells of the same field suggest
that it may be possible to develop a type-curve response that will
provide valuable information for project design and field
expansion.
SimulationresultsindicatethatpolymerfloodingandCDGfloodingmayproducesimilarfinaloilrecoverybut
polymer flooding will require more polymer mass. 12SPE 169705
TheHallplotrepresentsagooddiagnostictoolforperformanceevaluationofconformanceormobilitycontrol
methods including CDG. It gives solid indications of permeability,
skin effects, and changes in drainagearea (i.e., flow diversion)
supporting project interpretation. Detailed research and
development efforts are required and ongoing to better explain
possible mechanisms of CDG technology. Acknowledgments The authors
would like to thank TIORCO LLC for permission to publish this work.
Theauthorsalsogratefullyacknowledgethecontributionofoperatingcompaniesduringallphasesofproject
implementationandmonitoring.SpecialthankstoDeliaDazyNicolasSaezAbadia,forvaluablediscussionsofCDG
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