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 for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does notnecessarily reflect any position of the Society of PetroleumEngineers, its officers,ormembers.Electronicreproduction,distribution,orstorageofanypartofthispaperwithoutthewrittenconsentoftheSocietyofPetroleumEngineersisprohi bited.Permissionto reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment ofSPE copyright. 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 experience in Argentina. 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