SPE-174584-MSPotential Evaluation of Ion Tuning Waterflooding
for a Tight Oil Reservoirin Jiyuan OilField: Experiments and
Reservoir Simulation ResultsQuan Xie, Desheng Ma, Jiazhong Wu,
Qingjie Liu, Ninghong Jia, and Manli Luo, Research Institute of
PetroleumExploration and Development of PetroChina, Beijing,
ChinaCopyright 2015, Society of Petroleum EngineersThis paper was
prepared for presentation at the SPE Enhanced Oil Recovery
Conference held in Kuala Lumpur, Malaysia, 1113 August 2015.This
paper was selected for presentation by an SPE program committee
following review of information contained in an abstract submitted
by the author(s). Contentsof the paper have not been reviewed by
the Society of Petroleum Engineers and are subject to correction by
the author(s). The material does not necessarily reflectany
position of the Society of Petroleum Engineers, its officers, or
members. Electronic reproduction, distribution, or storage of any
part of this paper without the writtenconsent of the Society of
Petroleum Engineers is prohibited. Permission to reproduce in print
is restricted to an abstract of not more than 300 words;
illustrations maynot be copied. The abstract must contain
conspicuous acknowledgment of SPE copyright.AbstractLow salinity
waterflood (LSF) is a promising improved oil recovery (IOR)
technology. Although, it hasbeen demonstrated that LSF is an
efficient IOR method for many sandstone reservoirs, the potential
ofLSFintight oil reservoir isnot well-established. Thispaper
presentsasystematicevaluationof thepotential of low salinity
waterfloding for the tight reservoirs in Jiyuan Oilfield, China.
This investigationpushes the application envelope of low salinity
waterflooding towards the reservoir with low permeability(lower
than 0.5mD), formation salinity of up to 45,180ppm, reservoir
temperature of 70C and in-situ oilviscosity of 0.6 cp.Our
laboratory evaluation included zeta potential tests for interface
of oil/brine and brine/rock,thermodynamicanalysis
throughdisjoiningpressurecalculation, corefloods
usingrepresentativecoresamples.Thermodynamicanalysisshowedthat
decreasingdivalent cationsandsalinitymakestheelectricalcharges at
both oil/brine and brine/rock interfaces become strongly negative,
which enhanced therepulsive forces between oil and rock due to the
double electric layer expansion. As a result, the rock turnsmore
water-wet. Secondary corefloods were conducted with two different
brines, which include
shallowaquiferwaterandiontuningwaterwithconsiderationoffieldapplication.
CorefloodingExperimentalresults were history matched to obtain the
relative permeability curves. Results showed that compared
toshallowaquiferwater, low-salinitywaterexhibitedahigheroil
relativepermeabilityandlowerwaterrelative permeability at the same
water saturation and a lower residual oil saturation to
water.Laboratory results were input into a reservoir simulator to
investigate the potential of low-salinity
waterfloodinJiyuanoilfield.Itshowedthatsuitablyformulatediontuningwater(ITW)hasthepotentialtoaccelerate
oil production and improve displacement efficiency, thus resulting
in a higher recovery factorwith only a fraction of pore volume of
low-salinity water injected.To conclude, this paper demonstrates
that ITWF has a good potential as an IOR/EOR technology intight
reservoirs, the key points are described as follows. Firstly, the
mechanism of ITWF was interpretedby thermodynamics of wettability.
Secondly, laboratory experiments have shown that
ITWFcouldimproveoil recoverybyacceleratingtheoil
productionrateanddecreasetheresidual oil production.Thirdly, the
potential of ITWF in a tight oil reservoir in Jiyuan oilfield is
investigated using a mechanisticmodel based on input data of
laboratory experiments.IntroductionWaterflooding technology has
been the most successful approach to improve oil recovery. The key
pointto reach this success of waterflooding is that the
differential pressure can be formed by the water
injection,whichisnecessarytodisplaceoiloutofformation.Andalso,waterfloodinginvolvesmuchlowercostinvestment
and convenient operation. However, it was found that water
chemistry and salinity level
haveasignificantinfluenceonoilrecoveryfromtheexperimentsinthelaboratoryandfieldtrials(Mahani,Sorop
et al. 2011, Skrettingland, Holt et al. 2011, Xie, Wu et al. 2012,
Parracello, Pizzinelli et al. 2013,ShaikhandSharifi 2013, Shalabi,
Sepehrnoori et al. 2014). Inrecent years, several
mechanismswereproposedtoaccounthowtheionstuningwaterfloodtorecoveradditionaloil.
(1)Finesmigrationandclays swellingcausedbyions
tuningwaterfloodarethemainmechanismof improvedoil recovery(Morrow
and Buckley 2011, Sohrabi and Emadi 2013). (2)Multi-component ionic
exchange between therock minerals and the injected brine was
proposed to be as the major mechanism to enhance oil
recovery(A.Lager 2006, Lager, Webbet al. 2008). (3) Expansionof
thedoublelayer tobeasthedominantmechanism of oil recovery
improvement(Nasralla and Nasr-El-Din 2012). The general agreement
amongresearchers is that low salinity waterflooding cause
reservoirs become more water-wet (Fjelde, Asen et al.2012, Nasralla
and Nasr-El-Din 2012, Sohrabi and Emadi 2013, Shalabi, Sepehrnoori
et al. 2014).However, the potential evaluation of ion tuning
waterflooding in the low permeability reservoirs (lessthan 0.5mD)
is rarely investigated, especially from interfacial scale
(nano-scale) to core-scale to mech-anistic model. This paper
presents a workflow of ion tuning waterflooding and unveils the
potential of iontuningwaterfloodinginJi Yuantight oilfieldinChina.
Aquarter of fivespot model
wascreatedtoinvestigatethecontrollingfactorofiontuningwaterflooding,
withconsiderationoffracturingeitherproducer or injector and
fracturing both of wells.ExperimentsExperimental fluidsCrude oil
from Ji Yuan oilfield was used for zeta potential and coreflooding
experiments. Three differentbrineswereusedintheexperiments,
includingformationbrine, shallowaquiferwaterandiontuningwater. The
compositions of the brines were listed in Table 1.Mineralogy of
core plugsThe core plugs for zeta potential and coreflood tests
were extracted from the Ji Yuan oilfield. The contentof clays was
analyzed by X-ray test to unveil the importance of the clays on the
low salinity EOR-effectin low permeability reservoirs, as shown in
Table 2. The reservoir cores were rich in clays, which was inthe
range of 2030%, mainly in kaolinite and chlorite. Even the core
plugs were extracted in the
sameformationwithalmostsamedepthoftheformation,
themineralogyofthecoreplugsarestilldiverse,Table 1Composition of
the different brinesBrinesIngredients (mg/l)TDS (mg/l)
KNaCa2Mg2HCO3ClSO42Ba2Formation brine (FB) 14700 2090 286 0 27072
515 489 45,152Shallow aquifer water (SAW) 848 241 75 49 730 1620 0
3,564Ion tuning water (ITW) 853 10 5 45 510 1100 0 2,5232
SPE-174584-MSespeciallywithdifferenttotalclayminerals,whicharerecognizedthemainfactortoinfluencethelowsalinity
EOE-Effect (Morrow and Buckley 2011, Nasralla and Nasr-El-Din
2014).Zeta potential testsZeta potential technique was applied to
understand the relation between electric double layer
andwettabilityregardingthechargesatinterfacesofoil/brineandsolids/brine.
Rockwettabilityiscloselyrelated to the thickness of water film
between rock surface and crude oil, which depends on the
electricaldouble layer repulsion and Van der Waals force (Buckley
1989, Hirasaki 1991). Wettability of the rockwill be determined by
the stability of the water film, which is bounded by the interfaces
of oil/brine andsolid/brine (Hirasaki 1991, Tang and Morrow 1999).
An unstable water film, or thin water film, may
causethewettabilitytobepreferential tobeoil-wet. Therefore,
injectionwaterwithdifferent iontypesandconcentration will trigger
the alternation of the surface charges at both interfaces oil/brine
andsolids/brine. Then, oil film may detach from the pore wall by
increase of electrical double layer repulsionand the oil recovery
will be improved (Takahashi and Kovscek
2010).Threeexperimentalcoresandcrudeoilwereusedforzetapotentialtestwiththreedifferentbrines,including
formation water, shallow aquifer water (SAW) and ion tuning water
(Figure 1). Zeta potentialtest results show that the ion tuning
water resulted in zeta potential at interfaces of oil/brine and
brine/rockstrongly negative, compared with formation water and
shallow aquifer water, due to the low salinity andfew divalent ions
presence. The zeta potential test also shows that lowing the
salinity and divalent cationsmight be helpful to increase the
double layer expansion and peel the oil film off from the pore
wall.Coreflooding experimentsAll of the coreflood experiments were
conducted under 70C and the core plugs used in the experimentwere
extracted from the Ji Yuan oilfield. The parameters of experimental
cores were listed as Table 3. TheTable 2Mineralogy of the
experimental core plugsSampleMineral type and content (%)Total clay
minerals(%)Composition of clays and content (%)Quartz Potash
feldspar Soda feldspar
CalciteSmectite(%)Illite(%)Kaolinite(%)Chlorite(%)A 36.9 13.8 20.9
8.9 19.5 9 7 46 38B 40.2 7.8 21.2 30.8 26 14 36 24C 34.9 9.4 15.5
22.6 17.6 15 13 50 22Figure 1Zeta potential results of interfaces
of oil/brines and brines/reservoir rockSPE-174584-MS 3brine
permeability of the experimental cores was lower than 0.5 mD. A
Quizix-SP-5400 pump with theaccurate control at the constant
lowflowrate was usedinthe floodingsystem. The
experimentalprocedures adopted in this paper were given as below.1.
Core plugs of approximately 2.5 cm in diameter were cut from the
whole core, which was drilledfrom the reservoir with formation
brine.2. Thecoreplugswereevacuatedfor10hours,
andthenweresaturatedwithformationbrineforanother10hoursatroomtemperature.
Theporosityofthecoreswascalculatedfromthebulkvolume of the rock and
the weight difference between dry weight and the weight of core
saturatedwith formation brine.3. Afterwards, the initial water
saturation (i.e. irreducible water saturation), Swi, was
established byinjecting 510 PV of mineral oil with the viscosity at
15.5 mPa.s in room temperature in each ofthe direction. It was
injected at a rate of 0.1 mL/min with a net confining pressure not
exceeding3MPaunderroomtemperature. Theweight
ofthecoresbeforemineral oil displacement wasmeasured to calculate
the Swi.4. Then, the volume of the mineral oil was displaced by the
crude oil used in the experiment under70C and the cores were put
inside of the oven for four weeks to restore the wettability.5.
Ultimately, the core plugs were flooded with experimental brines
with flow rate at 0.025 ml/minat the 70C to obtain Sorw. The volume
of oil displaced by the experimental brine and the weightof the
core before brine displacement were measured to calculate the oil
recovery factor.The experimental procedures to quantify LSF were
well discussed in the literature(Masalmeh, Soropet al. 2014). In
this study, three coreflooding experiments were executed by using
two different brines
(iontuningwaterandshallowaquiferwater)undersecondarymode,
duetolimitationofamountofrepre-sentative core plugs from the
reservoir. The core plugs, however, were saturated the simulated
formationwater,followedbydesaturationbyusingcrudeoil.Thenthosecoreplugswereputintoovenforfourweeks
under reservoir temperature to restore the wettability. According
to the waterflooding history of JiYuanoilfield, shallowaquifer
water wasinjectedtotheformationfor pressuremaintenanceat
verybeginning. Table 1 shows that the salinity of shallow aquifer
water is already much lower than formationbrine. But the ion tuning
water EOR-Effect was explored by further decreasing the divalent
cations. Theoil recovery and pressure drop from the coreflooding
experiments were showed in Figure 2 and Figure
3.Figure2showsthationtuningwaterexhibitshighermeasureableoilrecovery(8.4%)thanshallowTable
3Parameters of the core plugs in the coreflooding expermentsSample
Length (cm) Diameter (cm) Porosity (%) K klink (mD) Swi(%) Sorw (%)
RF (%) Formulations1# 5.93 2.52 11.06 0.38 23.8 33.2 56.4 Shallow
aquifer water2# 5.91 2.52 11.32 0.43 21.1 27.8 64.8 Ion tuning
water3# 5.92 2.52 10.53 0.42 18.9 31.4 61.3 Ion tuning water4
SPE-174584-MSaquiferwaterunderalmost equivalent initial oil
saturation. It alsoshowsthat suitableformulatedthecomposition, ion
tuning water, can accelerate the oil recovery, compared with the
shallow aquifer water.However, lower incremental oil recovery was
observed from core 3#, compared to core 2#. This could
becontributed to the lower initial water saturation of core 3#.
Therefore, it will be uncertain to qualify thelowsalinityeffect
without historymatchingtoderivetherelativepermeability,
sincethecoreplugs,saturated with different initial water
saturation, would present a range of oil recovery factors. In this
case,the low salinity EOR-Effect was confirmed by the history
matching the oil recovery and pressure drop,which was discussed in
simulation part of this study. Above all we must mention that
further corefloodingexperiments,
includingiontuningwaterfloodingundertertiarymodeshouldbedoneandalsohistorymatched
to further confirm the low salinity EOR. But in this study, the ion
tuning waterflooding
undertertiarymodewasnotperformedduetothelimitationofrepresentativecoreplugsandcurrentoilfieldproduction
(shallow aquifer water was injected under secondary
mode).Thermodynamic analysisHirasaki has
investigatedthethermodynamics of thethinfilms
todeterminetheinterdependenceofspreading, contact
angleandcapillarypressureusingtheDLVOtheoryandLaplace-YoungEquation(Hirasaki
1991). The intermolecular forces comprise of the van der Waals,
electrical and structural forces(Hirasaki 1991, Busireddy and Rao
2004).(1)Figure 2Coreflooding experiments with different brines,
oil recovery vs. injected timeFigure 3Coreflooding experiments with
different brines, pressure drop vs. injected timeSPE-174584-MS
5WhereTotalisthedisjoiningpressureofthespecificintermolecularinteractionswhichreflectstheinteractive
forces between the interface of water/oil and water/rock. A brief
introduction of the forces andcalculation procedures are presented
as below.Van der Waals ForcesThe Van der Waals forces are
considered to be negative for the systems and the structural forces
and theelectrostatic forces are positive forces. The Van der Waals
and structural forces are assumed to be sameat all values water
film thickness and molarity. The London-van der Waals force between
the two similarmaterials is usually attractive; therefore, this
force is recognized as the strength of the attachment betweento
solids. The retarded London-van der Waals attractive force is
expressed as (Hirasaki 1991)(2)Where A is the Hamaker constant in
an oil/water/solid system, is the London wavelength, and h isthe
distance between the two plates.The Hamaker constant for a film
system is calculated from the experimentally for two identical
bodiesin a vacuum. These experimental values are in agreement with
the theoretical calculation.(3)Where 1,2,3 are the static
dielectric constants, k is the Boltzmann constant, 1(iv),
2(iv),3(iv) arethe electronic absorption terms, T is the kelvin
temperature. The Hamaker constant for oil/silica in wateris
approximately 11020J(Hirasaki 1991). Melrose(Melrose 1982) used the
Hamaker constant rangingfrom 0.3 to 0.91020J. In this study,
0.81020J was used as the Hamaker constant, and the Londonwavelength
is assumed to be 100 nm(Hirasaki 1991).Electrostatic ForcesThese
forces are as the result of the development of the charges between
interacting surfaces. The chargescan be formed either by
dissociation of the surface charges or adsorption of the charges
onto an unchargedsurface. The electrical double layer force is
estimated using zeta potentials and is approximatedby(Gregory
1975)(4)Where r1,r2 are the reduced potential, is the reciprocal
Debye-Huckel double layer length, nbisthe ion density in the bulk
solution, kBand is the Boltzman constant.Structural ForcesThe
structural forces are short-range interactions at a distance of
less than 5nm. However, the London-vander Waals and electrical
double layer forces are long-range interactions compared to the
structural forces.The structural interaction is calculated
from(Hirasaki 1991b).(5)Where Ak is the coefficient and hs is the
characteristic decay length for the exponential model. In
thisstudy, it is assumed that the coefficient is 1.51010Pa and the
decay length is 0.05 nm(Hirasaki 1991b).Disjoining pressure
calculations were listed as blow, including formation water,
shallow aquifer water,and ion tuning water (see Figure 4). Results
show that shallow aquifer water makes the interfaces
betweenoil/brine and brine/rock become repulsive force, thus
resulting in thicker and stable water film, comparedwith formation
water. On the contrary, formation water cause the film between the
interfaces of oil/brine6 SPE-174584-MSand brine/rock become
unstable since the attractive forces were formed. Metastable film
was generatedwith presence of shallow aquifer water according to
the shape of the disjoining pressure curve. Accordingto the
thermodynamics of wettability, the van der Waals attractions have
power-law dependence on
thedistancebetweenthesurfaces,whilethedoublelayerforcesareelectrostaticrepulsionsthatrisemuchmoreslowlywithdecreasingdistance.
Theinteractionbetweentheinterfaces closelyrelatedtotheelectrolyte
concentration and surface charge density. Surfaces of zero-charge
only van der Waalsattractions occur, whilefor highlychargedsurfaces
indiluteelectrolyte, thereis astronglong-rangrepulsion(Saramago
2010). In this theory, decreasing salinity always brings thicker
water film between theinterfaces, but the higher charged surfaces
might be obtained if the divalent cations can be removed fromthe
injection water. Figure 4 shows the good potential of ion tuning
water, compared with shallow aquiferwater and formation brine.
However, the further investigation needs to be done to confirm the
low salinityEOR-Effect, including coreflooding experiments and
reservoir scale simulations.SimulationCoreflooding history
matchingA one-dimensional homogeneous permeability core model was
established to simulate the characteristicsof oil recovery by
forced imbibition with the finite difference simulator ECLIPSE 100.
Cross-sectionalarea andlengthof the experimental core model were
reproducedtothe core model. There are 42equal-sized grid blocks in
the core model. The first grid which was located at the upstream of
the core wassaturatedwith100%formationbrinewith100%porosity, but
1000Dpermeabilitywasassignedtosimulatetheexperimentalinjection.Thelastgridattheoutletofthecorewassaturated100%oilwith0.001%
porosity and 1000 D permeability since at beginning of the forced
imbibition the outlet of the corewas filled with 100% experimental
oil. Porosity and permeability of each of the cells except of inlet
andoutlet cells was assumed to be equal to the permeability of core
plugs. Porosity was obtained by HeliumPorsimeter (PHI-220) under
roomtemperatureandpermeabilitywas
measuredthroughcorefloodingexperiment by injection of formation
brine with saturated core plugs. The schematic model and initial
oilsaturation of the model were shown in Figure 5.Figure
4Disjoining pressure vs. thickness with presence of various brines
(formation brine, shallow aquifer water, ion tuning
water)SPE-174584-MS 7According the the waterflooding simulation
through ECLIPSE 100, the significant parameters domi-nating oil
recovery and differential pressure by forced imbibition are the
capillary pressure and relativepermeability curves. The functional
forms in Eqs. (6)(8) are(6)(7)(8)Where krw is the water relative
permeability and kro is the oil relative permeability. Pc is the
capillarypressure, and S is the phase saturation. The subscripts w,
wi and wo represent water, initial water, residualoil
andwatersaturationwherethecapillarypressureisequal tozero,
respectively. Thesuperscript *denotes the
end-point.AccordingthetheiontuningwaterfloodingsimulationthroughECLIPSE100,
giventwosets ofsaturation functions, one for the low salinity and
one for the high salinity, the saturation end points arefirst
modified as:(9)(10)(11)(12)F1 is the function of the salt
concentration, Swco is the connate water saturation, Swcr is the
critical watersaturation, Swmax is the maximum water saturation,
Sowcr is the critical oil saturation in water.Figure 68 shows
history match results for shallow aquifer water and ion tuning
water flooding undersecondary mode. Both oil recovery and pressure
drop were successfully history matched and the relativepermeability
curves were derived, which were showed in Figure 8. Non-uniqueness
of history match wasnot considered due to the fixed parameters,
including Swi, Ko(Swi), Kw(Sorw) and Sorw. Additionally,the
capillary end effect can be ignorant for the minor influence in the
low permeability (less than 0.5mD)coreflooding experiments, due to
the low capillary number (10111010).Figure 5Schematic model of
experimental core plugs8 SPE-174584-MSRelative permeability curve
of ion tuning water was derived from Core 2#, but it can also
history matchthe oil recovery and pressure drop of Core 3#, shown
in Figure 8. The same relative permeability curveof iontuningwater
floodingcanbeusedtohistorymatchtwocoreplugs withdifferent initial
oilFigure 6History matching results for core plug 1#Figure 7History
matching results for core plug 2#Figure 8History matching results
for core plug 3#SPE-174584-MS 9saturation. It shows that the
relative permeability of ion tuning water flooding was constrained
reasonably.This is also an approach to decrease the non-uniqueness
of history match to derive the
relativepermeabilitycurves.Figure9showsthationtuningwaterfloodingexhibitshigheroilrelativepermea-bilityandlowerwaterrelativepermeabilityandresidualoilsaturationthantheshallowaquiferwater.Capillarypressurecurveswerenotshowedherefornon-sensitivityinthelowpermeabilitycoreplugshistory
matching.Potential evaluation of ion tuning water by a mechanistic
model
simulationJiYuanGeng271oilfieldwasdeltafrontsubfaciesdepositsandthedistributionofsandbodieswasclosely
associated with sedimentary micro-faces, including the underwater
distributary channels,
channelmouthbar.Theoriginoftrapformationwasrelatedtothelapoutofthesandbodiesandthelithologydensityshade,
whichshows that the reservoir was lithological deposit.
Formationtestingandpilotproduction of the drilled wells show that
the reservoir is not associated with edge and bottom water
andwasmainlydrovebytheelasticdissolvedgasinthedepletion.AsofMay2014,therewere119waterinjection
wells and 355 oil producing wells in Ji Yuan Geng 271 oil field.
All the oil-bearing layers wereperforated. The reservoir has
beenundergoingshallowaquifer water (SAW) injectionfor
pressuremaintenance from 2011 onward. As of 2014, the recovery
percentage of OOIP was 2.69%, and the rateof oil production rate
was 0.57. The well pattern of oil production is inverted nine-spot
pattern, and allofproducerswerefracturedwithhalf-lengthat about
100meters, but most oftheinjectorswerenotfractured. In this study,
a quarter of five spot were created to investigate the potential of
ion tuning waterflooding,
withconsiderationoffracturingeitherproducerorinjectorandfracturingbothofwells.
Theparameters of the box model used in reservoir simulation were
listed in Table 4.Figure 9Relative permeability curves for shallow
aquifer water and ion tuning water10
SPE-174584-MSAccordingtothecurrentoilfielddevelopment,
alloftheproducerswerefractured, butmostoftheinjectors were not
fractured, except for a few injectors, which were converted from
oil producers at highwater-cut. One of the main reasons to fracture
the oil producer without fracturing injectors is that the
stressdistributionundergroundisquitechallengingtofullyunderstand.
Theinjectors,
whichwerefracturedwithoutunderstandingstressdistributionwell,
couldbeconnectedtoproducersthroughfractures,
asaresultofearlywaterbreakthrough.Inthispartofstudy,amechanisticmodelwasestablished,withoutconsiderationof
heterogeneityinthehorizontal andvertical directions,
toinvestigatetheiontuningwaterflooding potential. Figure 1011 and
Figure 13 show the simulation results under secondary modefor both
ion tuning water and shallow aquifer water.Table 4Parameters of box
model used in reservoir simulationGrid cells NX13, NY13, NZ188Size
of box model L130m, W130m, H74.3mPorosity 0.11Permeability 0.5
mDIn-situ water viscosity 0.5 cPIn-situ oil viscosity 0.6
cPReference datum depth from mean sea level 2680 mReference
pressure 270 BargMax injection pressure 400 BargMax injection rate
12 Sm3/dMin production pressure 100 BarMax production rate 12
Sm3/dFigure 10Oil recovery vs. injection time with only producer
fracturedSPE-174584-MS 11Figure 11 shows that ion tuning water can
slightly improve oil recovery after water breakthrough intenyears,
inamodel withfracturingproducerinsteadofinjector. It alsoshowsthat
iontuningwatercannot only prolong the water breakthrough time, but
also reduce the water-cut. Figure 12, however, showthat
bothiontuningwater andshallowaquifer water canacceleratetheoil
productionbyfracturingFigure 11Oil recovery vs. injection time with
only injector fracturedFigure 12Schematic model of a quarter of
five spotFigure 13Oil recovery vs. injection time with producer and
injector fractured12 SPE-174584-MSinjector instead of producer. It
also indicates that ion tuning water can lengthen the water
breakthroughandbringthewater-cut down, comparedwithshallowaquifer
water, whichis consistent withonlyfracturingoilproducer. Therefore,
iftheundergroundstressdistributioncanbefiguredout,
fracturinginjectorsinsteadofproducerscouldbemuchprofitable,comparedwithfracturingproducersinsteadofinjectors.Figure
12 and Figure 13 show the results of fracturing both injector and
producer. Figure 12 shows theoil distribution by waterflooding in
15 years. Figure 12 and 13 also shows very clearly that fracturing
bothwells can accelerate oil production rate greatly, compared to
fracture either producer or injector.Simulations indicate that
fracturing injectors are far more significant that fracturing oil
producers.However,
theundergroundstressdistributionisthekeytomakesurethatfracturinginjectorsisundercontrol,
without channelling between the producer and injector. Figure 13
also illustrated that ion tuningwater had a great potential in the
reservoir scale as both injector and producer were fractured. One
of
thebiggestchallengestodeveloplowpermeabilityreservoirsbywaterfloodingistoestablishtheeffectivedifferential
pressurefrominjectorsandproducers. Figure10andFigure11showsslight
lowsalinityEOR-effect after water breakthrough, due to the limited
water injection in the low permeability as shownin Figure 14, which
shows limited water injection rate observed in the box model with
either fracturingproducer or injector. Relatively higher water
injection rate was observed in the model with both injectorand
producer fractured. In this case, low salinity EOR-Effect performs
much higher potential than the iontuning water injection in either
producer or injector fractured.Figure15showsthat, inthebothinjector
andproducer fracturedmodel, 0.3PViontuningwaterinjection under
secondary mode, followed by shallow aquifer water flooding, can
obtain the equivalent oilrecovery, comparedwithconstant
iontuningwater floodingunder secondarymode. However, thewater-cut
of constant ion tuning water flooding can be decreased in 30 years,
as a result of lower waterrelativepermeabilityintheiontuningwater,
comparedwithshallowaquiferwater. Simulationresultsindicatedthat
onlyafractionof iontuningwater injectionmight achievesignificant
incremental oilrecovery, compared with shallow aquifer water.
However, it should be noted that this is an ideal modelwithout
consideration of heterogeneity.Figure 14Water injection rate vs.
injection time with different fracture scheme (Shallow aquifer
water)SPE-174584-MS 13ConclusionsIn this study, zeta potential
tests and thermodynamics analysis were performed to investigate the
potentialofiontuningwaterfloodinginJiYuanoilfield.
Corefloodingexperimentswereconductedandhistorymatched to derive the
relative permeability curves for the mechanistic model to show the
potential of iontuning water. Several observations were made in the
following. Iontuningwatercancausethezetapotential at
theinterfacesofoil/brine, brine/rockbecomestrongly negative,
compared with shallow aquifer water and formation brine. Disjoining
pressurecalculationshowsrepulsiveforcesbetweentheinterfacesof
oil/brineandbrine/rockwithiontuning water. Coreflooding experiments
were history matched to derive the relative permeability curves for
bothshallow aquifer water and ion tuning water. It shows that the
ion tuning water can accelerate theoil production rate by
increasing the oil relative permeability and decrease water
relative perme-ability and reducing the residual oil saturation. A
quarter of five spot model were created to investigate the
potential of ion tuning water
floodinginthelowpermeabilityreservoirs. Simulationresultsshowthat
iontuningwater hasagreatpotential in reservoirs as long as
waterflooding has good sweep efficiency, which needs to
fracturebothproducersandinjectorsproperly.
Simulationalsoshowsthatonlyafractionofiontuningwater injection
might achieve significant incremental oil recovery, compared with
shallow aquiferwater.
Simulationalsoindicatesthatfracturinginjectorsarefarmoresignificantandeconomicalthanfracturing
the producers. However, these findings are completely based on the
clearance of stressdistribution underground and geological model of
reservoirs.AcknowledgementTheauthorswouldliketothanktheResearchInstituteofPetroleumExplorationandDevelopment
ofPetroChina for permission to publish this paper. We acknowledge
that this study was sponsored by CNPCwith a project-New Approaches
to Enhance Oil Recovery in Low Permeability Reservoirs, project
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