Nettability Literature Survey—Part 1: Rock/OiVBrine Interactionsand the Effects of Core Handlingon WettabiiityWilliam G. Anderson, SPE, Conoco Inc.

s

Summary. Nettability is a major factor controlling the location, flow, +d .@stributiOn Of fl~d? @ areservoir. The wettabdity of a core will affect almost all types of core analyses, including capillary pressure,refative permeability, waterflood behavior, electrical properties, and simulated tertiary recovery. The mostaccurate resuks are obtained when natiye- ‘or restored-state cOr~ Me ~ with native cmde Oil~d brine atreservoir temperattrre and pressure. Such conditions provide cores that have the same wettab~ky as thereservoir. ~. .’

The wettabih@’ of, ori&lly water-yet reservoir rock can be altered by the adsorption of polar com~oundsand/or the deposition of organic materiaf ‘that was originally in tie crude oil. The degree of alteration is deter-mined by the interaction of the oil constituents, the mineral su~ace,. and tie brine chefi$~. The PrO:~uresfor obtaining native-irate,” clesned, and rsstored-state cores are diSCUSSe4ss we~ aS the eff@s Of cOnng,preservation, and experimental conditions on nettability. Also reviewed are methods for artificially controllingthe wetmbflity during laboratory experiments.

htrodirotionThis paper is the first of a series of literature surveyscovering the effects”of nettability on core analysis. 1-3Changes in nettability have been shown to affect capil-Iq pressure, relative permeability, waterflood behavior,dispersion of tracers, simulated terdaiy recovery, imedn-cible water saturation (IWS), residual 01 saturation(ROS), and electilcal properties. 4-26 For core analysisto predict the behavior of a reservoir accurately, the net-tability of a core must be the same as tbe nettability ofthe undisturbed reservoir rock. A serious”problem occursbecause many aspects of core handling can drastically af-fect nettability.

Water-Wet, Oil-Wet, and Neutrafly Wet. Wettabfityis defined as “the tendency of one fluid to spread on oradhere to a solid surface in the presence of other irmnis-cible fluids. ” 7 In a rock/oif/brine system, it is a meas-ure of the preference that tie rock has for either the oilor water. When the rock is water-wet, there is a tenden-cy for water to occupy the smsll pores and to contact themajority of the rock surface. Siarly, in an oil-wet sys-tem, the rock is preferentially in contact with the oil; thelocation of the two fluids is reversed from the water-wetcase, and oil will occupy the small pores and con~ct tiemajority of the rock surface. It is importunt to note, how-ever, that the teim wettabWy is used for the wettingpreference of the rockand does not necessarily refer tothe fluid that is in contact with tie rock at any given time.

For example, consider a clean sandstone core that issaturated with a refined ofl. Even though the rock sur-face is coated with oil, the sandstone core is still preferen-tially water-wet. Thk wetting preference can be

coP&h!1986society.+Pe!role.mEngineers

lm’ral of Petmlc.mTechnology,October19S6’

demonstmted by allowing water to imbibe into the core.The water will displace the oil from the rock ,surface, ~-dicating that the,rock sui’face “prefers’? to be in contactwith water rather than oil. Simjkwly, a cow samra!ed withwater is oil-wet if oil will imbibe into the core and dis-place water from the rock surfuce. Depending on the spe-citic interactions of rock, oil, and Mne, the wwab@of a system can range from itrongly water-wet to str022g-Iy oil-wet. When the rock his no strong preference foreither oif or water, the system is said to be of neufml (orintermediate) wettabfi~. Besides strong and neutkd net-tability, a third ~pe is fracdonsl nettability, where differ-ent areas of the core have different wibing preferences. 27

The wettabfity of the rocklfluid system is impoitantbecause it is a major factor controlling the location, flow,snd distribution of fluids in a reservoir. .Jn general, oneof the flizids in a porous medium of uniform wettabilkythat contis at least two immiscible fluids will be the wet-ting fluid. When the system is iu equilibrium, the wet-ting fluid will completely OCCUPYthe smsllest pores andbe in contact with a majoriv of the rock s~face (ass~-ing, of course, that the saturation of the weting fluid issufficiently high). The nonwetting fluid will occupy tiecenters of the larger pores and form globules that extendover several pores.

In the remainder of this survey; the terms wetdizg sndnonwetting fluid wilf be used in addkion to water-ivet andoil-wet. This will help us to draw conclusions about a SYS-tern with the oppositi wetibility. The behavior of oif ina water-wet system is very similar to tle behavior of waterin an oil-wet one: For exmuple, it is generally assumedthat for a system with a strong wetting prefererice, thetietting-phase relative permeab~ky is only a function of

1125’

ABLE 1—DISTRIBUTION OF RESERVOIR WETTABILITIES BASED ON CONTACT ANGLE34

ContactAngle Silicate Carbonate Total

(degrees) Resewoirs Reservoirs Reservoirs “

Water-wet o to 75 13 2. 15Intermediate wet 75 to 105Oil-wet 105to 180 1: A 3;

Total 30 25 55

its own saturation-i. e., it shows no, hysteresis. 7,12,28 fected the wettsbflity behavior in the contsct-migle tests.Owens and Arch&28 measured the gas/oil drainage per-mea.bflily, where the oif was the strongly wetting fluid,and compared it with the water/ofi imbibition relative por-‘meahii@, where the water was tie strongly wetting fluid.The water-imbibkioi reIative permeability (stronglywater-wet system) was a continuation of the oil-drainagerelative permeability (strongly oif-wet system), demon-strating the amdogy between systems of opposite wetta-bilities.

Historically, afl petroleum reservoirs were believed tobe strongly water-wet. This was based on tyo mjor fac~.Fust, almost all”clean sedentary rocks are stronglywater-wet. Second, sandstone reservoirs were depositedin aqueous erivironments into which oil later migrated.It was assumed that the comate water woufd prevent theoil from touching the rock surfaces. In 1934, Nuttingzgrealized that some producing reservoirs were, in fact, ac-@ally strongly oil-wet. He found that the quaitz surfacesof the Tensleep sandstone in Wyoming had adsorbedheavy hydrocmbons in layers about 0.7pm tldck (about1,000 molecules) so fdy that they could not be removedby gasoline or vzrious solvents.”When $e hydrocarbonfilm was removed by ,fuing the core, the film could berestored by soaking the cores in crude oil overnight.

Examples of other reservoirs that are genertiy recog-nized as sirongly oil-wet are the Bradford sands.of theBmdford pool,, Pennsylvania, 30-32 and the Ordovicisrrssmds of the Okkiborns City field. 33 More recentfy,Treiber et aL % used the water advancing contact angleto eiamine the wettabdity of 55 oil reservoirs. fn thisprocedure, deoxygenated synthetic fofmation brine anddead anaerobic crudes were tested on quartz and calcitec~stafs at rescrvom temperamre. COnta~. angles (mea.+.ured through the water) fromOto750 [0 to 1.3 rad] weredipmed water:we~ from .75 to 105° [1.3 t6 1.83 rad],intermediate wet; and from 105 to 180° [1.83 to 3:14 red],oil-wet. As summarized in Table 1, 37 of the reservoirstested were classified as oil-wet, 3 were of intemnetilatewegabtity, and 15 were water-w.et. Most of the oil-wetreservoirs were mildly oil-wet, with a contact angfe be-tieen 120 and 140° [2:1 and 2.4 rad]. Of the carbonateresemoirs included, 8 % were water-wet, 8% were inter-mediate, and S4% were oil-wet. Most of the carbonate

. . reservoim were from the west Texas area, however, sothere is a geographical bias in the data.

Treiber et al. cautioned that these tindlngs could notbe considered representative of a trufy random samplhzgof petroleum reservoirs. The sainples were bkmed because(1) all were operations for the sarnb company, (2) mostwere being considered for some type of flooding, and (3)some of the reservoirs had demonstrated unusual be-havior. A fourth consideration is how much the use ofdegassed fluids rather than the real formation fluids af-

1126

As ,iiscussed later, this probably causes amoverestima-ticm of the oil-wetness. Therefore, the large percentageof reservoirs found to’be ol-wet is less significant thanthe general indications that not all reservoirs are water-wet and that the r&ervoir wettabilky varies widely.

Contact-sngJe measurements made by Clilingm sndYen35 suggest that most carbonate reservoirs ramge fiornneutrally to oif-wet. They measured the we~bdity of 161limestone, dolomitic liiestone, calcitic dolomite, ariddolomite cores. The cores tested included (1) 90 coresfrom Asrnari limestones and dolomites from tie Mid$eEasG (2) 15 dolotite cores from west Texas; (3)3 coresof Madison liiestone from Wyoming; (4) 4 cirbonatecores from Mexican oil fields; (5)”4carbonate cores fromthe Rengiu’oil field in the People’s Republic of China;’(6) 16 csrbonate cores from Albe~ (7) 19 chalk coresfrom tie North.,SeT (8) 5 samples from India+ amd (9)5 samples from Soviet oil fields in the Urals-Volga region.Table2 shows the distribution of wettsbfities with 80%of the reservoirs either oil-wet or strongly oil-wet. Some.of the strongly oil-wet reservoirs were oil-wet bew+seof a bitumen coating. Note that the range of contact an-gles considered to be neutrslly wet is smaller thari therange given in Table 1. This demonstrates the variation

, from paper to paper of the cutoff angles between ?Jedifferent wetting statea.

As discussed iu more detiril later, reservoir rock canchange from its &iginal, strongly water-wet condition byadsorption of polar compounds and/or the de ositjon of

3Porgsnic matter originally in the crude oil. 7, 6-42 Somecrude oils make a rock oil-wet by depositing a thick or-ganic film on the mineral surfaces. Ofher crude oils con-ti pOlar compounds that cm be adsorbed to make therock more oif+vet. Some of these compounds are srrffi-ciently water soluble to pass throu~ the aqueous phaseto the rock.

Fractiormf Wettabilfty. The retilzation that rock wetta-bflity can be akercd by adsorbable crude oil componentslexito tie idea that heterogeneous forma of wettabiity existin reservoir rock. Generally, the intend surface of re.ser’-voir rock is composed of many minerals with differentsurface chemistry and adsorption properties, which maylead to variations in nettability. Fractional nettabilityslso called heterogeneous, spotted, or fhlmationwettabifky-was proposed by Brown and Fatt27. audothers. 43* fn fkactioml wegsbdity, crude oif compo-nents are strongly adsorbed in certain areas of the rock,so a portion of the rock is strongly oil-wet, whie the rest@strongly water-wet. Note tit this is cqncepty+flydiffer-ent from intermediate wettsbtity, which assumes that allportioim of the rock surfsce have a slight but equal prefer-ence to being wetted by water or oil.

lomnalof PetmlaunTechmlo8y,@to&r 1986

hfi@ Wettibifity. Salatfrie147 introduced the termririxed wettabilby for a special type of fractional netta-bility iri which the oil-wet surfaces form continuous pathsthrough tie larger porca. 48-50The smafler pores remainwater-wet and contsin no oil. The fact that sll of the oilin a miixed-wettabflity core is located in the lager oif-tvet pores causes a.smdlbut finite oil permeabtlty to ?x-ist down to very low oil sahrrdtiom. T@ in mm pertitsthe drainage of oil during a waterflood to continue untilverj low oil saturations are reached. Note that the maindistirrction betywen mixed md fractional wettsbtity is that@.elatter, implies neither specitic locations for the oil-wetsurfaces nor continuous oil-wet paths.

SalatMet visualizes the generation of mixed nettabilityih,,tie following manner, When od yufially invaded anciiiginilly water-wet reservoir, it displaced waler from thelarger pores, while the smaller pores remained water-fi!kdbecairse 6f capillary forces. A mixed-tiettabihty condl-:tion occuried if the oif deposited a layer of oil-wet or-ganic, material ody on those rock surfaces tliat were indirect contsct with the oil but not on Me brine-coveredsurfaces. Oil-wet “deposits would not be formed in thesmall water-ffled. pores, snowing them to remain water-wet. The question that Salatliel did not address was howthe oil first came into direct contact with the rock. As theoil moyes into the larger pores, a tfdn layer of interstitialwater remains on @pore walls, preventing the oil fromcontacting the rock. Under certain conditions, however,@e waterfdrn separating the crude and the mineml sur-face cm mpture. Hall et al. 51 sad Melrose52 recentlydeveloped a theoretical model for the stability of thesethiri water films that shows fiat the water ftis becomethiier and thinner as more oil enters the rock. The waterfim is $tabflized by electrostatic forces arising from theeIectficaf double layers at the oillwater and wateif rockinterfaces. 51’54As tie water “fifmthickness is further re-duced, a critical tlickness is reached where the water filmsin the larger pores become unstable. The films ruptureand are dkplaced, aflowing oil to contact ~e rock.

Native-State, Cleaned, and ReStored-State Coraa.Cores in three different stitei .of ,presepatioh are usedin core anafysis: native .Xaie,cleaned, and restored state.The best results for mrrftiphase-type flow mialyses are ob-klincd with mtive-ststi cmes, where alterations to the wet-tabfity of the un@rrbed reservoir rock are minimized. ‘.Ii thk set of paper~ the term “native-state” is used forniry core that was obtained and stored by methods thatpreserve the Nettability of the reservoir. No distinctionis made between cores taken with oil- or water-bakedfluids, as long as the native wektabflity is maintained. Beaware, however, that some papers dktin=gish on tie ba-sis of drilliig fluid (e.g., see Treiber et al. 34), In thesepapers, “native-state” refers only to cores taken with asuit8bIe ofl-fjjhte.t~e rhill:mg,mud, which nrtintains theoriginal connate water saturation. ‘:Fresh:state” refersto a core with unaltered wettabtity that was taken witha water-base d@ling mud that cbntsins no compounds thatcan alter core tiettabdity. Here, the term native-state isused for both cases.

The second type of ‘core is the cleaned core, where anattempt is made to remove all the fluids and adsorbed or-.ganic msterid by flowing solvents through the cores.Cleared cores are ususlly strongly water-wet and should

Journalof PetroleumTechnology,October19S6

I TABLE 2–DiStribUtiOn OF dARBONATERESERVOIR WETTABILITIES35 I

Water-wetIntermediate wetoil-wetStrongly oil-wet

‘contactAngle

(degreas)

O to 80.80 to 100100to 160160 to 180

Percent ofReservoirs— .

a

:15

be used.only for such measurements as,porosity and airpermeability where the wettab~lty will not affect theresults.

The third type of core is the restored-state core, in whichthe mtive nettability is restored by a three-step process.The core. is cleaned and then satrmtcd with brine, fol-lowed by crude oil. F,@ally, @e core is aged at reservoirtemperature for about 1,000 hours. The methods used toobtain the.three different types of cnres will be discussedin more detail later.

Factors Affecting the OriginalReservoir WenabiiityThe &igiaal strong wa~r-wetness of most, rcservoi ~n-erals csn be altered by the adsorption of polar compounds.and/or the deposition of qr tic matter that was origi-

$nally in the crude oil. 7,20,3,32,36+155-63‘fhe surface-active agents io the oil aze generally believed to be p+wcom ounds that contsin oxygen, nitrogen, andlor SU1-..

!,@r. 6,37,40,41,SS,56,W68These compounds con@in botha polar and i hydrocmbon end. The polar end adsorbson the rock surface, exposing the hydrocsrbqz end andmaking the s+face more oil-wet. Experiments haveshownfhat some.of these aaturaf surfacfants are sut%cientfysolu-ble iizwater to adsorb onto tic rock surface aftcrpassingthrough a thin layer of water. 42,60S69-71

In addition to the oif composition, the degree to.whichthe wettabllity is aftcred by fhese surfactants is also deter-minqi by the pressure, tcmpermmc, mineml surface, andbrine chemistry, including ionic composition and PH. Theeffects of pressure and temperature will be discussed Mcr@the section on experimental conditions. The importanceof the mineral surface is shown by the contact-angle @eas-orementa +cbssed esrlier, ‘,3s in which a large majorityof tie carbonate reservoirs tested were. oil-wet, whileMany.of the sandstone reservoirs were water-wet: Sevemlresearchers have found that some polar compounds af-fect the wettabilky of sandstone and carbmaitc surfacesin ~lfferent ~ays, 37,+42,6672-76 The. chemistiy of thebrine can also alter the. wettabtity. Mrdtivafent cationssometimes enhance the adsorption of surfactants on thefiner~ ~“rface. %77-s3 ‘fhe brine pH is also impOrt8nt

in determination of the nettability and other interfacisfproperties of the cmdelbrinelrock system. 6Z26,~In afka-Iine floodmE, for example, allmhne chemicals can reactwith some c-fides to pr~duce surfactqts that sfter wett?-b~lty, 6,26

!.

Surface-Active Compormda in Crude Oil. ~ie thesurface-acfive components of crude tie found in a wide~ge ofWrolem fractions, 41 they are more prevalentm gze heavier fractions of cmde, such as re$ina and

\1:127

—

aaphaftenes. These surfactants are believed to be polarcompounds that contain oxygen, nit@gen, and/or suffer.The oxygen compounds, which are usually acidic, includethe phenols and a bwge number of different carboxylicacids. 67$5,86Seifert mid Howellsw showed that the car-boxylic acids are titerfaciilfy active at alkaline PH. Thesulfor compounds include the sulfides and tilophenes,with smaller amounts of other compormda, such as mer-~ap~s ~d polysulfides. 87,88The nitrogen compo~daare generaUy either basic or neutral and include csrba-xoles, tides, pyridenes, quinoliies, and porphy-~~. 40.s7-90me pVhYtis camf&m imerfadly activemetal/porphyrin complexes with a number of dii%erentm>tds, including nickel, vanadium, iron, coppr, “tic, titani-um, calcium, aud mirgnesinm. 9*-95

Because the .9zrfactarrts in cnrde oil are composed ofa lsrge number of very complex chemicals that representonfy a small fraction of the,crude, identi@g which com-

beeipossible ‘6pounds are im ortam in aftering the wettabtity has not

h addkion, attempts to correlate bulkcrude propert;ei with the abflity of the crude to ~ter wet-tabiliw have been unauccessf+ McGhee et al. 62 satn-rated Berek cores with brink, odflooded them to IWS withdifferent cnides, then incubated them at 140”F [60”C]for 1,0+30hours to allow the wet@bfity to reach equilib-rium. .TheU.S. BWearr of Mines (USBIvf)wettsbllily in-dex ‘wasthen meaaured and compared with bulk propwtiesof the crude. They found no correlation between theUSBM index and interfaci.d tension (IFT), organic acidcontent, percerit nitrogen, or percent suIfnr of the cnrde.

oCuiec96 measured the Arnott nettability index ofrestored-stnte cor6s and found no correlation between ivet-tabilky and amonnta of acids, basea, aromatics, resins,nitrogen, or srdfur. In all cases, when the restored-statecores were water-wet, the crndes bad low sapha.ftenesndanffur contents., However, other low-asphaftene”xnd low-mdtirr c@des rendered cores neutrally or oil-wet.

Experiments that determined the general mtnre of thesurfactxnts xnd the crude oil fractions in which they areconcentrated without attempting “~ determine exactlywhich compounds cause wet@bifity alteration have beenmore success~. Jolwnsen and Danningw,9s found thatasphzdtenea were responsible for changing some cmde-oiWwater/glass systems from water-wet to oil-wet. Thesystem ,was oil-wet when the cmde was used but wat&r-wet when the deasphalted crude was used; The addkionof a very small amount (0.25%) of the whole crude toOzedeasphalted crnderestored the oif-wettingness of thesystem. Donafdsbn aud Crocker55 ‘and Donafdson56measured wepabilky alte@ion caused by the polar coin-poaada extracted from aeveml different mincmf oifa. First,the nettability of a series of uizcontanzinated Berea plugswas mcasnred”with brine agd a refied mineral oiL Theaverage USBM wettabilky iizdex was 0.81, or stronglywater-wit. After cleanirig, the USBM nettability indexof the plugs was measured with brine and a 5 % mixtureof the extracted polar organic componnda in the retinedmineral oil., The phtgs were significantly leas water-wet,with USBM wettabtity indices ranging from 0.45 (water-wet) to -0.W (xretitmlfy.wet), demonstrating that polarcompmmda in cnide can alter the wettabtity. Note thatthere was appsfentfy no aging time with the polar cOm-ponnds in the plugs, so equilibrium wettxbifities may bemore strongly oil-wet.

/.,’112s

,,

Several researchers 57,5s analyzed wetkbiliw-afterirwcompounds extracted from cor~. Jennings58 r~moved ~portion of the nettability-altering cornpotirids by extract-tig a non-water-wet core with tolnene,, followed by a cfdo-rofordmethanol mixiure. An imblbitioiz test showed tbstsome of the wettabil@-idtering compounds had been re-moved during the s~ond extraction because the core wasmore water-wet. The material ‘remo+ed dtiring the sec-ond extraction contained porphytis ~d bigh-moledor-weight pamffinic and aromatic” cbmpoiihds.

Denekaa et al, 41 used a d~tiflntion pro;exs to separatecmde oifs into fractions of different molecular weight.A clean, dry core wax saturated with the crude oil frac-tion to be tested, then aged for 24 hotii:. An imbibitiontest based on the relative rate of imbibkion waa nsed todetermine the wettxbility Alteration..1“.1 The originxlcrqde oil and the heaviest residue left a,fterdistillation hadthe greatest effect on the nettability; they were the onlyfluids that nzadetbe rock oil-wet.’fhia fiplies that a con-siderable portion of the surfact+ds, in the crude oiI hada large molecular weight. Many of the lower-molecular-’,weight fractions, however, also debreaaed the water-nettability, demonstrating that the surfactants in crudehave a broad range of molecufa.r weights. Cuiecg6 ob-tained similar results. Note that Denekas et al. and Cuiecbotlr used@ cores and that idso~tiob of the w&ttnbility-.ikering cOnzpoundswoufd probably have been ilteredifthe cores contained brine during tie aging “process..

A number of roaearchera have examined the i@rfacinUyactive materiak that are cOncentrat&dat the Oil/water in-terface. Generalfy, these materi~s can iilso be adsorb@on tie rock surface to sfter wettsblli~. 3.7,8~g9-*mBar-tell and Nlederhauser 103managed @ sepirate these,ma-terials from ~e crude oil dqd f6und that they, formed ahxfd, black. noncrys@fline substxnce tit was sapI@ticin nature.

. .Adsorption Through Water F~s. Experiments hoveshown tfiat nataml surfactants. ii cimde.are often suffl-cienify soluble in water to a&sorb onto the rock surface ,-&r passing tbrougb “a thin ld~er. of water. 42,60>69-71Meaauremerits comparing aaphd~ene a+orption in coreswith and without water show tlwt m many. caaes a waterfilm wiUreduce but not completely ir@it =pk+lterfe”nd-sowtion. 6M9,70 Be&use the wa~ei .qzd asphaltenes wMcoadsorb, however, the wat4.rfilm may alter tie detailedadsorption mechanism. 70,1w Lyutin @d Burdynm foundthat the asphalt&e adsorption f$ornA&h ,crude in an yn-consolidated sandpack wai about 80% of the dry y~ueat a water saturation of 107. PV, decreasing to 40 % whenthe water sapration was incrth+ed to 30% PV. Berezinet al. 69 exmzzizzedthe adsorption of .&phalten&s&d ;ex-ins from crude onto cleaned sandstone cores. With Tui-mazy crude, a water,satnration of about 17% reduced theadaoz’ption by about a factor. of three. With two othercrndes, a water saturation of about 20% completely. in-hibited the adsorption. Such complete inhibition by tie,water fifm woidd be expected in reservoirs that remainwater-wet, with no significant ,adsorption:from the cmde.

Reisberg ad Doscherbs aged clean glaas slides inc~de ofi. floating above brine and observed the forma-tion of oif-wet fti. The formation i.nd s~bility of theoif-wet fti on the slide was observed by lowering .!-beslide into the brine and observing whether the brine dis-

Joumalof PetroleumTechnology,October1986 ‘

“placed alf of the cmde ofl from the slide. They first ageda clean glass slide in crude mrdfound that a film, d6positedover several days, made the slide moderately oil-wet.They modified the experiment by immersing the slide inwater before aging it in crude. Surprisingly, the oil-wetfti formed much more rapidly. when a NaCl solutionwas used instead of water, the slide also became oil-wet,but it was necessary to age the slide for a longer periodof time.

Sandston& mrd Carbonate Surfaces. The types of min-eral surfaces irr a reservoti are also im ortarrt in deter-

Emi@rg wettabfity. Both Treiber et cd. and ClriHngaiad Yen35 found that carbonate reservoirs are wpi@y.

more oil-wet than sandstone ones. Two other sets of ex-periments show that the mineral surface interacts with thecmde oil imposition to detefine wettabWy. The firstset e~nes the adsorption onto silica and cm’bonatesur-faces of relatively simple polar crrmpoundy the secondset exnmines the adsorption of crirde.

Simple Pokr Compounds. Whsin the effects of brinechemistry are removed, silica tends to adsorb simple or-gtic bases, wh~e the carbonates tend to adsorb simple~rgaic tilds. 37,Q83 This occurs because silica normallYhas a negatively charged, weakly acidic surface in water

nenr neutral pH, while the carbonates have positivelycharged, weakly bssie surfaces. 37,@,83,105

These surfaces will preferentially adsorb compoundsof the opposite polarity (acidity) by m acidbase reaction.Wettabili~ of silica will be more strongly affected by theorganic bases, whfie the carbonates will be more strong-ly affected by the organic acids. This was found to be theCW+in experiments on the adsorption and nettability al-te~tion of refntively simple polar ,compormds oir sand-stone and carbonates. The compounds were dksolved ina nonpolm oil, and the contact angkeof the oillwatcrhnin-eral system was measured on mr initially km, stronglywater-wet aystal surface. &xreraHy, adsorption mrd wet-tabifity nkemtion occurred with basic compounds on theacidic silici surfaces and acidic compounds on the basicccrbomte surfaces. Acidic compounds had very little ef-fect. on sifica, and basic com ounds had litde effect onffieCabonat=.37A42,66.7S.7’J.o~l~Note,however, thatmost of the ,adsorbed compounds chmrged the wettabfiVonly from strongly to mildly water-wet, rather than tooil-wet.

The acidic compounds that adsorbed and nftered thewettab~l~ of the carbonates in preference to silica in-cluded naphtherric acid 37.109mrd a number of carbox$;ic acids (RCOOH), including capryfic (octanoic ,psfmitic (.hexadecarroic), 42 stearic (@adecanoic), 210,10s

and oleic (cis-9-octadecnnoic) acids. 42 Basic compoundsthat adsorbed on the acidic silica surfaces included iso-qrdno~ne37and octadccykmzine [CH3(CH~17NH~. 1ffi,108@mz40 and Morrow ei al. 66 exded dze adsorptionand wettabilhy alteration on quartz “imddolomite of a num-ber of relatively low-molecukw-weight compounds foundin crude oils. Basic nitrogen compounds gave advancingcontact angles up to 66” [1.15 rad] (water-wet), withhigher angles for qrrnrtz than dolumite. Sulfur compoundstested provided arzgfes of 40” [0.7 rad] or less withrto systematic dlffercrrces between the two surfaces, Thecontact angles either were stable or decreased with time(i.e., the system became more water-wet). The acidic

oxygen compounds gave higher airgles on dolumite.tbsnquartz, up to 145° [2.5 rad] for. octanoic acid[CH3(CH2)6COOHJ and up to 165° [2.9 rad] foc law-ic acid [CH3 (CH2),0 COOH]. Note, however, that tbe

uxygen-containing acidic compounds appesr to reactgradualfy with the dolomite, so the contacf angles ae un-stable and the sy$em gadu?dly becomes more water-wet.Cram if.ail noted that none of the relatively simple com-pounds they tested could create a stcble, oil-wet yu’face.There fure, they cuncluded that the compounds respomi-.blefor wettabihty alteration in crude were higher-weightpolar compounds and other po+ons of the asphaltenesand resins.

In the inure complex crudeibrinelrock systems, the nrin-er# surface will not necessarily have a preference forcompounds of the opposite acidhy. The simple systemsdkcussed here tested each surfactcrd individpaUy and re-moved the effects of brine chemismy. @ tke section onbrine chemistry, it will be shown thnt multivalent cationscnn promote the adsorption of surfactants with the sameacidigi as the surfcqe. fir addition, “the adsorption of auysingle surfactant in the crude might’ be enhanced ordepressed by the adsorpion of other compounds.’

Adsor@on From Crude. A nnmber of researchersfound differences in the adsorption of crude oil cum-punerits onto dry sandstone and carbonate sur-faces. 41,72-74,l@,110Denekss et al. 41 sepmated out theacidic and basic orgaric compounds from crude arrd test-ed them in initially clean, dry cores by tie method de-scribed earlier. They found that the wettabfity ofsnndstone was altered by both the acidic and basic com-pounds, while the Iiiestone was more sensitive to the ba-sic nitrogenous orgmric compounds.

Several experimenters have compared the adsorptionof asphnbenes from crude onto initially clean, dry sazrd-packs composed of either quartz or disaggregared” corematerial that contained both quartz and carbonate. 72,110They found that adsorption was greater in disaggregatecore material. Tumasyan and Babclyan 110.measured theadsorption, of asphaltenes from Kyarovdag cmde ontoquartz and cleaned, disaggregate Kynrovdag core m~-terial @atconticd 10.4 % carbonate. The adsorption wncabout 8x 10’4 mg/cm2 for qumtz nnd about 18x 10’4mglcmz for the core material, mr iacrease of more thana factor of two: Abdurashitoi ef al. 72 meaarzzedthe ad-sorption of asphnfte”nesonto sida-sized fractions of purequartz samds and sends containing both quartz and car-bonate. They found that the adsorption on the qunrtz sandswas as much as an order of magnimde lower Own the ad-sorption on the sands containing both minerals. These re-”srrks are very qualitative, however, because the speCXcsurface arei of the quartz packs was lower dum the areaof the mixed mineral smrdpacks, which afso reduces the~onnt of adsorption.

Brine Chemistry. The salhrity nrzdpH of brine ae veryimw-t in determining wettabiilg because they stronglyaffect the surface charge on the rock surface and fluid in-terfaces, which in turn can affect the adsorption of .srrr-factants. ‘o,‘m Positively charged, cationic srrrfactantawifl be attracted to negatively chnrged surfaces, whilenegatively charged, anionic surfactcnts will be attractedto positively charged sin-faces. The surface charge of Q.ica and ccfcite in water is positive at low pH, but nega-

Journd of Petml..m T-hnology, October 1986 1129

tive at high PH. For sifica, the surface becomes negatively

char ed when the pH is increased above about 2 to!3.7, 3,105 whfle calcite does not become negatively

char ed untif the pH is greater than about 8 to9.5. &,’05.111As discussed in the previous section, sili-ca is negatively charged near neutral pH and tends to ad-sorb organic acids, whiIe cafcite is positively charged andtends to adaorb organic bsaes. Calcite will adsorb cation-ic sm’f@mJts rather than anionic surfactants., however,if the pH of the solution iJJ which it is immersed is in-creased above 9.111

The pH also affects the iotiation of the snrface-activeorganic acids and basea in the crude.’. fn afkahe water-floo’iling, a relatively inexpensive caustic chemical–typically sodium hydroxide or sndium ofiosificate-isadded to the injection ,water. 112The hydroxide ion msctswith organic acids in acidic crude oils to produce surfac-tanta that after the wettabiti~ ador adsorb at the oilhine

interface to lower f.FT. Seifert and How.ells85 exsminedthe interfaciafly active materials in a California cnrde oil.They found that the crude contained. a large mount Ofcarbnxylic acids that form soaps it ilkaline PH.

The possibfity of EOR during amalkaline flocaldepcndaon the pH and salinity of the brine, the a.sidi of the crude,

?’and the origiwd wettabtity of the system. 2,113,114Cookeet al. 6 discussed the effects of salkhy nn wettxb~ky inalkaline flonds where the soaps are formed by the inter-action of the alkaline water with the acidic ‘crude oil. Inrelatively fresh water, the snaps that are formed are soht-ble in water; promoting water-wetness. If the system isinitially oif-wet, EOR may occur b a wettabdity rever-

.?~~ from ~fi..wet to ~a~r-wet. 17.2 ,114J 15 On the ~ther

hand, in high-salinity systems, EOR may occur as,a re-sult nf awater-wet-to-oil-wet wettnbifky reveraaf. Aa thesaliniw is increased; the soaps become almost in.duble,adsorb on the rock surfaces, and. promote” oil-~en~g, 6.113If the system is initially water-wet, COok

et al. ststf that EOR in a highly sshme ~ystem may oc,curby a water-wet-to-oil-wet tiettability reversaf mech-~sm.6 ,113,114

In silkdoillbrine systems, multivalent metsl cationsin @ebrine can reduce the solubilky of the crude sur-factants andlor promote adsorption at the mineraf sur-faces, causin the system to become more oil-

?wet. 6,W,77,79,8.116,117Multivalent metal ions that havealtered the wettabifity of such systems include Ca ‘2,

Mg’2, Cu’2, Ni’2, and Fe’3. Treiber et al. 34 exam-ificd the effects of trace “metalions in the brine on the wet-tab~hy. They meakured the contact angles on quartz ofdead Werobic cmdes in deoiygenated synthetic fofma-tion brine and found that as little as 10 ppm of Cu’2 orNi’2 coufd change the wettab~ky fcom watdr-wet to oiI-wet. Brown and Neusta.dterm placed cmde oil dropletsin a contact-angle apparatus tilled’ with dktifled water.They found that Oreaddition of.less than 1 ppm of Ca’2or Mg’2 would alter the nettability, making the systemmore oil-wet. The addition of trace amounta of Fe’2 alsochanged the wettabiIity with some of the crudes tested.The.$emultivalent ions have SISObeen ahown to incresaethe od wetness of soils stab~ied with cut-backxaphalt..11S,119 (Cutback ~~~t ‘is ml MPildt ==ted ‘iti

an inexpensive solvent, such as gasoline, to reduce theviscosi~.) HaiIcnck11s - Seved strongly water-wet

soils with cut-back asphalt. He fokd that the oil wetness

of the anil after the.asphalt tre@zent waa greatly increaaed’by pretreating the soif with a solution of ferric or @mi-IJU222sulfate.

Morrow et al. xl aged glass sfidca in Moutray crude,waahed the slides to remove the bufk crude, and then usedisooctafre and distilled water. to meaaure tie water-advancing angle. They fonnd that the wettabifity strong-ly depended on the sfnount of trace ions iJJthe system.When the glaas slide was extremely clean, no residual fbwas depnsited by the crnde, and the system was water-wet. Next, they treated the glass with femic (Fe’3 ) or”orler transition metal ions before exposing it to drecnide.They obtained contact angles up to 120 to 140” [2.1”to2.4 rad], with the angle dependent on the choice of ion’and its c&rcentration. The”ferric ion was pxrticulady ef-fective in altering the wettabilky.

There appexr to be two related reasons for ~e effectsof these mnftiv#ent ions on the wettabili~. Fiiat, they ~,can reduce the snlubility of the surfactants in the crudeandbrine, helping to ‘promote oil-wetting. 6,113Second,they behave as “activators” for the smfactants in thecrnde. “Acdvator” .la a term used in the floption indus-try for ions or cnmpounds thst, while not snrfact@ them-selves, enhance surfactant adsorption on the mizrerafsmface snd increase the flnatabifity. Generally, the acti-vators act like a bridge between the mineraI surface andtie adsorbing surfactant, helping tn bmd the snrfactantto the NIffsce. go AS shown previously, clean @J~ haaa negatively charged surface nnd tends to adsorb @osi-tively charged) orgnnic bases from solution. The (nega-tively chsrged) acida in solution will not adsorb on thesurface because they will be repelled by the like chargeon the quartz surface. For example, clean quartz is notfloated by fatty acids, ideating that tie quartz remainswater-wet. At the proper pH conditions, however, thewettabfity can be changed and the quartz can be floatedby the additidn of smafl nmounts of marry multivalentmetalfic cations, including Ca’2, Ba ‘2”, Cu’2, Al’3 iad Fe +3. WT%Q.107These ions adsorb on tie qun3t2surface, providing positively char.r@ sites for the adso%tion of”&e fstty ;~ds. -. -

,-.

For exam 1. Ga.din and Chang7s “imdGaudm andFuerstemm% ‘staled the adsorption of laurnte ions onauartz. When sodium Iaurate, CHa (CH2.) toCOONa, is~ded to the water, it dissociates @~ a ne~ati;ely chargedlaumte ion and a positively charged Na’ ion. Becausequartz develops a negative surface charge as a result ofthe dissociation of H + ions from the Si-OH groups onihe silica surface, the negatively charged laurate ion isrepelled ffom tie negatively charged quartz surface.Hence no adsorption occurs. However, adsorption occurswhen, for example, divafent Ca’2 or Ba’2 ions areadded aa the activator. These positive djwdent ions canadsorb on the surface, allowing the negatively chmgedsurfaciant (in this caae, the laurate ions) to adaorb in as-sociation wia them. Researchers with other experimen-tal systems also state that divalent ions can bind to anegatively charged”surfactant to fogn a positive, cationksurfactant/metal ~mplex, w.bich is then attracted to andadsorbs on the negatively charged quartz snrf?ce, 116,117

“CIays. Several researchers have studied tie adsorptionof aiphaftcnis Wd resipa onto clays, and found that.ad- ;sorption can make the clays more oil-wet. 70,76.1~, 120-133

,.1130’ Journalof Pmol&m Technology,October1986

Clementz %120,121 eximined adsorption under mhy-droua conditions of the heafl ends—the nonvolndle, high-molecuiar-weight fraction-of cmde oil, which areprimarily asphal~nes snd resins. He found that rhe com-pounds adsorbed rapidly onto montmorillonhe, forminga stable clay/organic compound and chsnging the netta-bility from water-wet to oil-wet. Clementz also lookedat adsorption under anhydrous coiiditions of the heavyends onto Berw’corca that contain significant amounts ofkaolinite. The adsorption of tie heavy ends made the coreneutrally wet as determined by an imblbhion test. The ad-sorption also,reduced the expansion of swelling clays, claysurface area, cation exchange capacity, and water sensi-tivity. The ‘materials that adsorbed onto both the mont-morillonite and kaolinite were difficult to remove,although most of them could be exmacted with a chloro-formlacetone mixture.

Clementzused dry cores and clays. As discussed C&er, the presence of a water fdm will gen@ly reduce theadsorption of wettabfity-altering materials, typically bya factor of two to four, although in some cases, it willcompletely inhibk adsorption. ‘>@ Collins and Melmse70measured the adsorption onto kaolinite of asphaltenes dk-solved in tolucne. The dry clay adsorbed a maximum ofabout 30 mg asphaltene/g clay. The addkion of 6.6%water t? the clay reduced the adsorption to 13 mg/g. Inaddition to reducing the adsorption, the water l@ mayalter the d:tied mechanism of asphaltene adsor@on be-cause the asphaltenes and water will coadaorb. 7 For ex-ample, in contrast to his work with anhydrous cores,ClemenE found that the adsorption of asphaltene ontoBerea cores in the presence of water dld not reduce thewater sensitivity of the kaoliidte. lW

Non-Water-Wet Mineral.% When all of the surface con-taminants are carefully removed, most minerals, includ-ing quartz, carbonates, and sulfates, are wronglywater-wet. go,1o7,lx From flotation studies, however, afew minerals have been found that are naturally but weaklywater-wet or even oil-wet. These minerals include sul-

“fnr; graphite, talc, coal, snd msny sulfides. Pyrophyllheand other talc-like silicates (sificates with a sheet-liie&rncture) are ~obably also neutrally wet to Oil-~et, 30,107,134-12~ese finer~~ ~ ~OW~ tO be SO~e-

what hydrophobic because air can be used to float themon water ir3froth flotation, implying a large waterlairhnin-eral contact angle. Because they are non-water-wet withair, it is probable that they are also oil-wet.

On the bsais of core-cleaning attempts in a limited num-ber of reservoirs, it appears that cores containing conl aresometimes na.tur@ly neutrally wet because they can becleaned only to a neutfsll wet condition rsther than a

z~Uon lY wa~r.wet one. 1 a,129 Cuiec96 and Cuicc et8al. 13 cleaned unpreserved cores with different solvents

and then measured wettabdity. In four cases where corescontained large ixnounts of unexmactable organic carbon,they were able to clean the cores only ti neutmf nettabil-ity. Wendel et al. 12s cleaned core from the Hutton reser-v6ii contaminated with an invefi-oil-emulsion drillingmud. Core from most zones in thk reservoir could becleaned to a water-wet state. However, in one zone thatcontained si=tilcant amounts of coal, the core was neu-trally wet after cleaning. About 50% of the rock surfacein tie neutrally wet zone was covered by a thin layer oforganic matter less than 300 ~ [30 mn] thick. ThISfayer

Journalof PetroleumTechnology,October1986

--

may be a:rcauftof dif3i3si0nof organic cmnpounda releasedduring diagenesis from the small, organic, detrital pard-cles of cod scattered throughout the zone. Unforhmate-ly, this is unclear at present. Thin sections from bothwater-wet and neutrally wet (tier clcaqing) zones showthat both contain approqtely equal amounts and dis-.@bution of woody coal; algae coal, and pyrite. Conse-quently, it is unknown what causes the postcleaningneutral tiettability of this neutrally wet zone.

Boneauand Cfampitt 131and Trantham and Cknnpitt 132stite that the oil wetness of the North Burbank unit iscaused by a coating of chamosite clay (Fe3Al zSi2O IO. 3HzO) on the pore surfaces rather than the more com-mon, strongly adsorbed organic coating. The chamositeclay, which is iron rich, covers about 70% of the rocksurfaces It seems plausible that tbe chamosite cfay rendersthe core oil-wet because, as discussed earlier, iron ionsare strong activators, promoting o~-weufng. Cl~pitt*

states that unpubliahti contact-angle measurements madewith all of the ~emls “inthe No&Burbank core ahowedthat chamosite M naturally oil-wet.

Artificial Variation of WettabifityAadescribed previously, a native-state core contains acmmplexmixture of different compounds that can adsorband deaorb, possibly altering the wettabdity during an ex-periment. Msny re8esrchers have tried to simpfify theirexperiments by artificially control~mg the wettabfii~ tosome constant, uniform value. The three methods mostcommonly used are (1) treabnent of a clean, dry core withvarious chemicals, generally orgWOcMOrOsfl~es “fOr.sandstone cores and naphtienic adds fOrwbOnat~ core~(2) using sintered cores witi, pure fluids; and (3) addingsurfacthnts to the fluids. A sintered tdlon core with purefluids is the preferred method to obtain a uniformly wet-ted core because tic wetrabili~ of these coma is constantsnd reproducible. The fiettabilhy of cores treatid withbrganochlorosilan:s, naphthenic acids, or stirfactanta ismuch more variable because it afso depends on such vari-ables”as the chemical uked, the concentration, tie treat-ment time, the rock surface, and the brine PH. Thesetreatments have advantages, however, when he~rOgen~-ous wettabtity or wettsbil~ alter~tion is studied.

Organochlorosffanes and Other Core Tr&dmMa. One.method of making a sandatone core uniformly non-watcr-wet is to treat it with a solution conpining an OrganO-~~oro~~e ~ompo”nd, 133-139vm~tiom of ~~ tf~~t-

ment have also been used to create fractionally wetted~mdpacf&&+$50.1@h!2~d mixed-wet cores. 143me ~r-

ganosilane compounds contain silicon molecules with at-tached chlorines and non-water-wet organic groups, with.the general formufa RnSiC14-n where R is usuallymethyl or phenyl and n =0, 1, 2, or 3.133 These sub-stances ,react with the hydroxyl (OH) groups on silicondioxide surfsces, exposing the organic groups and ren-dering the surface non-water-wet. For example, dimerhyl-dichlorosilane, (CH3)2SiC12 (Drifilm@ or Teddol@ ),chemisorbs on the outside of the sificate lattice of glass,eliminating HC1 and exposing CH groups, which reduce

hthe wata-wetness of the surface 1 Other compounds il3-clude heximethyldkilazane 138 and trimethyMdo!Osi-kme. 145The wettabfily of the core is altered by flowing.P.rsmtic.nnm.nimtimwithR.L.Clmnpiu,Ptiltip Petroleum,BaII[esvilleOK,Dac.1S83.

1131

a solution of the organosilane through it, snowing a suffi-cient time for the reaction to occur, and then flushing theunreacfed compound from the core. Some control of thechange in we,ttabifi~ can be achieved by variation in theconcentration of organosilsne in the solution. For a com-plete description of the method, see Ref. 134.

In addition tu unifoqnly treating cores, organocldorosi-kmca are used to prepare fractionally wetted sand-Packs, 43,46.50,140-142 Sand gtins txeated with 6rgm30-

chlorosilmies sre mixed witkuntrcated; water-wet sands.‘The fraction of oil-wet surface is aasumed to be the sb.meas the fraction of orgnndcblorosilane-treated sand. Oneproblem, however, is that some of the organocblorosi-lane is known to be transferred to the water-wet sandgrains, likely changing their wettabtity.43 Auothermethod of obtaining fractioml nettability is to form ‘tieporous medium from water-wet (gkMs)beads and oil-wet(tcflon) beads. 146

Moh~~ ad s~tcr 143have reqedfy publiahcd a tech-nique to generate mixed-nettability cores so that the largepores have continuous’ water-ivet surfacca, leaving thesmalf pores ofi-wet. Note that in these cores, the netta-bility is reversed from Salatbiel’s47 mixed-wettabilitycores. Cleaned cores are first treated witi orgagosikmesto render them uniformly oil-wet. The treated cores aresaturated with oil, flooded with heptadecane to dkplacethe oil, and then flooded with brine to ROS. Because thecore is oil-wet, the large pores are fdlcd with brine, butthe small ones are fdled with oil. Brine and heptadecaneIMY then be injected simu&aneously to alter the fractionof pores ffled with oil or water. After the desired satura-tion is reached, the core is fust placed in a cold waterbath (50”F [1O”C])to freeze the heptsdecane, then an 11.5pH sodium hydroxide solution is injected to diapfimc thebrine. Mohanty and Sslter state that the alkaline solutionremoves the orgnnosilane coating from the lnrger, brine-tilled pores, leaving them strongly water-wet, while thefrozen heptadecane prevents auy change in nettability intie small oiLffled, oil-wet pores. Folly, t+e alksdineso-lutiori is displaced with brine, arid all of the fluids are re-moved, leaving a mixed-wet@ ility core. After thistreatment, the cores imbibed both oil and water, indicat-ing that areas of the. core were both water- and oil-wet.Unfortunately, Moh&y and Salter did not test the cores

: by oil flooding them to determine whether they had a verylow water.saturation after tie injection of “manyPV’s ofoil. This would have verified the formation of continu-ous water-wet paths through the large pores, which wouldbe analogous to oil-wet paths in Sala~el’i cores.

One problem with orgamochlorosilane treatments is thatthe nettability of the tmatcd core varirs depending on suchvariables as the orgtiocidorosil~e used, the concentra-

tion, the treatment iiine, the time elapsed since the sur-face was treated, and the pH of the brine. 147 Nodependable treatment has been reported for acgeving agiven: core wettahilhy. Note that many organosilane-treated cores ze only neutrally to mildly oil-wet, insteadof strongly ofl-wet. Coley et al. 134used General Elec-tric Co. s~lcone fluid No. 99 in concentrations rangingfrom ‘0.002sto 2.0% and were nhle to vmythe contactangle, in. glass capillaries only from 95 to 115° [1.7 to2 fad]. RathnieO et al. 137found that cores treated withdmethyldichlorosikme would still slowly imbibe water,indicating that the cores were at most neutrslly wet. In

1132

~onmt, Newcombe et d. 136 stated that contact an~essa large aa 154” [2.7 rad] could be obtained for aK1casur-faces mated with different conqamations of methylsilOx-ane polymer, but these contact angles tended to decreasetowsrd 90” [1.6 rid] as they aged. Memwat $?ral. l@tmatcd silica surfaces with various concentrations of fourdifferent organochlorosilanes and obtnincd contact anglesffom 75 to 160” [1.3 to 2.8 rad] with water and xyleneon the treated surfaces. Depcndmg on the specific treat-ment, they found that the contact angle could graduallyincrease or decrcaae aa the system aged. Because&e wet-tabtity of cores treated with organosikmes can range frommildly water-wet to strongly oil-wet depending on the Spe:cific treatment, the Amott or USBM method shoufd beused to determine the wettabllity of the treated core.

Quilon@ treatments are mother method that has beenused to alter the wettabiIity of sandstofie cores. Tiffii hndYellig 149treated Berea cores with Quiion-C@ to renderthem uniformly oil-wet. Workers at tie Petroleum Recov-ery Inst. have used Quilon-S@, i related com-~md, 15~153 me won compounds consist of a chrome

complex containing a hydrophobic fatty acid group in anisopropyl alcohol solution. When @iiori is injected intotie core, the molecules bmd to the surface, expose thefatty acid group, and render the rock surface oil-wet. 1XNote that wettabtity of the treated core probably v~ies,depending on concentration, tfcatment time, etc., so itshould be meaaured with the USBM or Amott metbnds.In many crises, the treated core is probably OIIIYneutral-ly to mildly oil-wet.

These trcatmerita have been used on sandatone core withthe chemical binding to the s~Ica surfaces. Orgsno-.chlorosikme treatments, which adsorb on silica surfacesby reacting with the hydro+yl grou$a, are generally noteffective on carbonate surfacea. 1 5,1% A number of~Wche~~ 109.155-157bWe used m hthenic acids torender carbomtc cores more ofl-wet. ?7 The naphtle~cacids react with the calcium carbonate to form cslciumnaphthenates, which are ofi-tiening. 109 Note thatnaphthenic acida will not nlter the wettabtity of saudatone.s~faces. ‘w

Sharma and Wuuderlich15s altered the nettability ofBerea pIugs by saturating’ them with au asphaltic crude:Drv Dlum were vacuum-saturated with isrhaltic cmde oil,th&’fl~shed with pentane, which ten& to precipita~asphakenca onto the pore walls. 67 The pentane was”re-moved in a vacuum, kwiug behind a layer of asphaltenes.Tim plugs probably had mixed wettnb~ky after Ecatmencboti,oil snd water would imbibe spontaneously. 3 An ad-vsutage of thk method is that it uses com@mda foundnatnrslly in the resetioir and ,pight be a more realkticticatrnent than the other trcahnenta discussed above. Note,however, that it is necessary to verify tiat the crude iscompatible with the pentie because some cmdes will plugthe core when pentane is injeded.

Artificial Coma. Several rcaearchera have used artificialcores and pure fluida to control wettab~hy. The uniformcomposition of tie core and the absence of surfactimtscombine to give a constant; uniform, and reproduciblenettability. The most popular material for the artificialcore baa been polytetiafluoroethylene (teflon). Stegemeierfid Jess&n159used porous packa of tcflon particles. Morerecent experiments hsve used consolidated teflon

Journal of Pekole.m Technology, October 1986

cores, 160-’68 which are prepared by compressing teflonpowder and sintering it at elevated temperatures toproduce a consolidated core. Mungan 167 completelydescribes the process. Lefebvr.e du Prey lm has 81s0us<dSinter.Sd5tifle88 8tee] and altina cores. ~,

Teflon is preferred for two reaaons: it is chemically inertand has a low surface energy. 16g Most minerals foundin reservoir rock have “ahigh sutface energy, so”abn08tall liquid8 will spread,,op and wet them against $r. Thew&abiMy of such high-energy solids must bec$mtroUedwith either adsorbed fti on the solid 8urface or 8urfac-tants in the fluids. Both of these inethod8 raise the prob-lem of changes in the wettab~ty during the experimentas a result of adsorptionldesorption phenomena. On theother hand, the surface energy of teflOn iS low enouti.that a wide range of contact angles can be obtained withvarious combinations of pure fluids that do not containsurfactants. The u8e of pwe flbids with teflon also avoidsdifflcukies with contact-angle hysteresis associated withadsorption/desorption equilibrium and the problems as-sociated with contact angle and ‘IFT aging phenomena.This”is dlscus8ed in more detail in Ref. 1. fiany experi-ments in tetlon cores use air or Nz anfl various fluida to

va~” the contact angle. Contact angles from Oto 1080 [0to 1.9 rad] can be obtained by the proper ChOiCeof liq-

161For ~x~ple, an air/water/teflOn sYs-ui~gas pati8.tern has”a contact angle through the water of 108° [1.9rad]. Lefebvre du Prey 160 used mixtures of water,glycerol, glycol, and alcohols to represent the water pbaaeand mixtures of pure hydrowbons for the oil phaae. Con-tact angles through the oil phase of from Oto 168° [Oto.2.9 rad] were reported for hk teflm, steel, and aluminacores.

Surface-Active Agents. The use of clean cores and puretkdd8 with various C0nCenmati013Sof a SiJigleSurfactant‘isthe third way that re8e81Cher8have controlled the net-tability of cores: Owens ,and Archerzs used biwiumdlnonyl 8ulfonate in the oil and reported stable contsctangles up to 180° [3.1 rad] on a quartz crystal. Morrowet al. 66 were uriable to reproduce this work, finding astrong time dependence for the contact angle. They triedto control the wetfabtity with octanoic acid, obtaining@-gles from Oto 155” [0 to 2.7rad] on dolomite. They foundthat the wettabflity could be maintained for less than aday, however, after which tlesystem became increa.$inglywater-wet as tie octanoic acid 81OWIYreacted with thedolomite.

A number of res&hers 17,26.17&174haVe I18Sd8mkJeS,R-NH2, to study EOR caused by Wettab~hy dtemtion iIIlaboratory &#.wflmds. Wwtability reversal from Ofi-wetto water-wet and. from water-wet to”oil-wet are two ofthe proposed mechanism for enhanced recove~ duringalkaline waterflooding. 114 In Oiese laborato~ 8tudies,clean core, a refined oil, and ibrine containing mineswere used. The wettabili~ was rever8ed by changing thepH from alkaline. to acidic. When the PH was alkalime,the amine group physically adsorbed on tie rock surface,exposing t& hydrocwhn cl@ to make the sUrfaCe0~-wet. 173The wettabilhy was altered when the PH becameacidic because tie mines formed water-soluble salts thatrapidly desorbed from the rock surfaces, leaving thern-water-wet, Hence a core that is oil-wet becomes water-

Jownd of PetJolam Technology, October 1986

,.

wet when, water conta.inhg a mild acid is injected. ”Themost cofnrnonly used amines have been hexylamine andn-@ylamine. Mungan 174measured the water-advancingcOnmct a@ on a siliii, syficc u8ing water, n-hexylamine, and a refined bid. Tbe contact angle with noaminca present was about 60° [1 rad], or water-wet. Asthe concentration of tines tias increaaed, tie contact an-gle gradually changed to about 120° [2.1. rad], or mildlyoil-wet. In addition to iltering the wettab~ky, the aminespartition between the oil and water and lower IFT.

Alteration of the OrighraI‘WettabflityAs mentioned previously, alterations in nettability canaffect the iesuks of moat core analyses. IdcaOy, tieie @-yse8 shordd be mu with core wettabfity that is identicalto the nettability of the undisturbed reservoir rock. Un-fortunately, many factors can significantly alter *i. wet-tabilky of thecore. The8e factors can be divided into twogeneral categories (1) tho8e that influenc&core wettsbikity before testing, such as drilliig fluit is,’packaging,preservation, and cleanin% and.(2) those that influencewettabiitv dtig testing, such m test fluids, temperahue,and pres&re. - -”

The wettabili~”of a.core can be altered during the drill-ing process by the flushhg aitionsof driig fluids, par-

ticularly if the fluid contsim 8urfactimts 128>175or ha8 apH~~.1i~.1?6 different 1% that of the reservoir fluids.The w@@biiv may also be changed by the pressure andtemperature drop that occurs as the core is brought to thesurface. This action expels fluids, particularly the lightends, and changes the spatial dkribution of the fluids.In addition, asphaltenes and other heavy ends may depositon the rock suifaces, making them more oil-wet. The tech-niques used in ba@.ling, packaging, and preserving thecore & slso alter the .wettability through a 10SSof lightends, deposition of heavy ends, and ofidation. The labo-ratory procedures for cleaning and preparing the core cmchange the wettabfity by altering the amount and type ofmaterial adsorbed on tie rock surface.

Factors that can alter wettabfity diu’ing testing includethe test temperature and pressure. Generally, cores nmat atmospheric coiidition8 are more oil-wet than those mnat ,reservoir conditiom becau8e of.the reduction iri”SOIU-.bility of wettabfity-akering compotindi. An additionalfactor iMuencing -he wettabfl~ is the choice Of testfluids; certain migerd oils camalter the wettqbility. Coreanalyses ze sometimes run with air/brine or airlmercu-v,in place of ofl and brine. ,These analyses ~nplicitly as-sume that wetfabfity effects are unimportant.

Currently, three different *of cores “ae used in coreanalysis: (1) the mtive-state ,core, where every effort ismade to maintiin the nettability Of the in-situ roch (2)the cleaned core, where the intent is to remove all of theadsorbed compounds from the rock and to leave the corestrongly water-we! and (3) the restored-state mm, wherethe core is firstcleaned apd ~en returned to”its originalwettabti~. These definitions are used in the majority ofthe more recent literature. However, in some papers, par-ticuk@y older ones, the term restored-state is used forwhat are actually cleaned cores (e.g., see Craig7 ). Thework with native- and restored-state core is at either mmbient or reservoir temperature and pressure, i.idfe cleanedcores are usually tested at ambient temperature.

1133

Native.State CoreCoring. In a nativi-stite (fresh) core, every precautionis taken to minimtie changes from the undkturbed reser-voir nettability condhion, starting when the core ig frostflushed by the dr~g mud. In pyticukw, a mid with s~-factants or a pH that ‘differs greatly from the reservoirfluids must be avoided. Ofl-based-emulsion muds ?ndother muds containing ‘surfactaits, caustics, mud thinners,organic coriosion, in&itors, and lign@fonates must beavoided. 175,177Note that, @hIlethey probably exist, nocommercially available oil-based muds have been m rted

P“thatcan preserve the reservoir nettability. 175>17’178The different coring fluids for obtaining native-stati

cye have been recomriended. (1) synthetic formationbrine, (2).unoxidized lease crude oil, or (3) a water-breedmud with a miniznuin of addhives. Bobek et al. 175rec-ommend coring with brine and noadditives. If ,.hk is notpossible, a water-based mud containing only bentonite,cnrboxymeibyl cellulose, rock salt,, and barite should beused. This is recommended b~ause they found that thiswould not alter the wembfiity of strongly water-wet cores.Note, however, that the carboxymethyl celkdose,may ~terthe wettabfit of oil-wet cores, rendering them more

2water-wet, 15 .~75Bbrlich and Wygsl 179recommend a

synthetic formation brine coritaining CaC12 powder forfluid loss ‘control and no o~er additives. Mungait 180rec-otiends coriug with lease crude oil. Note f.hatthere aretio possible problems with the use of crude oil: (1) itis flammable, and (2) surfactams can be formed by oxi-dation. of the cmde, which could alter tie wetta-bili@. ”,103

rhfortummly, very MtIe work has been published aboutthe effects of individual drilling mud components cmwet-tabiihy, particularly for oif-wet cores. Burkhardt .r al. 176exaniined the effects of mud filtrate flushing on restored-,stite”cores snd found no significant effects. Unfortunate-ly, the cores were in contact with the crude oil for only12 to 16.hours, so it is doubtfol that the wettabtity wasrestored before testing.

Bobek ei al. 175tested several dit%r<nt drillkm mudcomponerits used in water-baaemuds on both wat~r-wetand oil-wet pings The drilling mud :omp6nen@ to be test-ed were dksolved in or leachdwith distied water thenthe resulting solntion was filtcreii. Concentrations of thecompamds were chosen to duplicate those encounteredin the field: Water-wet limestone and s~dstone plugs weresaturated .wltb the test solution and wetibflity alterationmonitored by the irgblbkion method., As,dkcussed earli-er,’.they”fonnd flat rock salt, carboxymethyl celhdose,.bentonite, and bake had ho effect on tie wetmbfli~ Ofthese initially water-wet plugs. Starch, lime, tetmsoditirnphosphate, and calcium lignosujfomte altered the wetta-btity of the sandstone and/or limestone plugs.

Drilhg components that, did not.affect the water-wetplugs were tested on oil-wet sandstone plugs. The dry,initially water-wet plugs were made oil-wet before test-ing by saturation with Elk Basin crude and aging for oneday. Notethit becanse of the short duration of the aging,the wettabiity may not have been in equilibri~. The agedcores were flushed witi a drilling mud component fkraW,then the wettabfity was measured. by the imbibitionmethod. .Sa.kdid not affect the wettabfity, whfle carb-oxymethyl cellulose made. the plugs” more water-wet(bariti was not tested). Bobck et al. found that the PH

,.1134

of the filtrates was an iinpotit factor in we~bdity al-teration. The origti bentonite filtrate changed me wet-tzbtity from oil-wet to water-wet. When the pH waslowered into the neutml or acidic rsnge, however, no wet-tabtitjI reversaI”occurr+.

Sharma snd Wunderlich 158meaaurcd the wettabi!.iwaf-teration caused by different drilliig mu@components inwater-wet and oif-wet Berea plugs. The oil-wet Bereaplugs were prepared by treatment’witi an asphaltic crudeand pcntane, as discussed previously. Dry plugs weresaturated with brine, injected with 10 to 12 PV’s of thedrilling fluid component, aged for 15 hours; tien flushedwith 5 to 6 PV’s of brine. Wettabilky was measurd af-ter contamination by a combined USBM/Aniotl methoddeveloped by Shagna and Wunderlich 158and comparedwith the we~bility of control samples. The driiing comp-onents tested included bentonite,, carboxymethyl cellu-lose, Dextrid@ (an organic polymer), D~spac@ (apolyanionii ceflukiwe polymer), hydroxyetbylcelhdose,pregelatinized starch, and xanthm gum. These compo-nents are generally considered relatively bltid, with onfysmall effects on the wettiibilky. None of the componentsaffected the nettability of ~e water-wet plugs. However,N of the components, with the exception.of the bentonitefdtrate, made the oil-wet plugs significantly less oil-wet.This indicat&stie need for further rese~ch on acceptabledrillings muds for obtaining native-state core.

Several researchers have attempted unsuccessfully tofmd suitable commercially available oil-based muds for~btig ~tive.sate core, 175, 177, 178,~ of tie ~fi.ba~~

drilling mud iiltrates tesied made water-wet cores moreoil-wet. Unfortunately,. none of the reports identify tlzespecific drilling mud components used. ,

Cm-e Packaging and Preierv&ion. Once the core isbrought to the surface, it must be protected from wetWbtity alteration caused by the loss of light ends or depo-sition snd oxkldion of heavy ends., On exposure to air, .subticei k crizdecan rapidly okidize to form wkw prod-ucts that are surfactants, altering ihe wettabili-,W,34,73,103,115,175,181,182 M ad&tiOn, a tick ofl-w@

residue from the crude will be deposited on &e rock sur-face if the core is allowed to dry out. To prevent wetE-bility alteration, Bobek et al. 175 recommended twosltemitive packaging procedure: that are now gene@yused for native-state cores. The fwst ia to wrap the coresat the weUii@in polyethylene or polyvinylidene film andthen in aluminum foil. The wrapped cores we then sealedwith a thick layer of paraffin or a special plastic sealerdesigned to exclnde oxygen aid prevent evaporation. Thesecond, preferred method is to immerse the cores at tipwellsite in deoxygenated formation or synthetic brine ina glass-lined steel or plastic tube, which is then seafidto prevent leakage and the entrance of oxygen. ImbibGtion wettabihw tests showed that the nettability of corepackaged by either of these WO methods was unchangedfrom the wettabfily mesaimed at the wellsite. Instid ofdeoxygenated brine, Mungari180 recommended tit thecores be cut and stored in degassed l&ae crude oil. Mor-gan and Gordan 183and McGhee et al. 62 recommendedthat the cores be stored in their wetting fluid, either for-ntstion brine or crude oil. “Thewettabiky would be,deter-mined by an imblbhion test at the wellsite. Finally, not?that cores taken in a robber sleeve, fiberglass, or PVC

Journalof Petroleum Tedmo108y, Octpber 1986

TABLE 3—EFFECTS OF EXPOSURE TO AIR AND PARTIAL DRYING ONNATIVE-STATE CORE

Number Average . Averageof Cores Dlsplacement- Oisplacement-Tested iescriplion by-Water Ratio by-oi Ratio

2 Native state 0,97 0,003 Exposed to air at

70 to 100nF for 1 day 0.63 0.002 Exposed to air at

75°F for 60 days 0.42 0.004 Exposed to air at

225°F for 7 days 0.18 0.00

C’ay$btdnedbyuse ofthe Amattwellafl~v,,s, natNeNatecorefrom0,! Zone8., SterlingCo”nly,

L

1’liner can be DESeNed if the ends are capped’and sealed. approaches one as the water-wetness increases. Siniiiar:

A number-of experiments have dem&strated that ex-posure to air and drying cao alter the nettability of core.As discussed earlier, Treiber et al. w measured the.net-tability of 50 reservoirs usfig deoxygemted synthetic for-mation brine and anaerobic crude. In some cases, thecontact angle showed that the reservoir was water-wet.For some of those cnrdes, exposure to oxygen changedthe wettabili~ to ofi-wet. Bartell mrd Niederhauser103stodied interracially active materials in crude, which con-centrate and form solid fflms at the oil/water interface.These materiils can also be adsorbed on the rock surface,rendering it oil-wet. Crodes and brines were obteined andstored without exposure to oxygen. Most of these crudesshowed very little interfaciel activity. On exposure to air,the cmdes developed moderate-to-strong fdrn-fomningtendencies, while the oil/water IFT was lowered by asmuch as 50 %, indicating that surfactants were formed byoxidatiori of the crude...

Richadson et al. 1s2 stored core’ from a mixed-wettability reservoir47 using four different methods. Ox-idation snd drying of the core tiere prevented with thefirst two methods: (1) core wrapped in foil and scaled inparaffh and (2) core stored in evacuated (deoxygenated)formation water. The other methods were (3) core storedin aerated formation water and (4) core stored in clothcore bags. The cores were oilflooded with kerosene toIWS and then waterflooded. The average ROS for thesamples protected from oxidation and drying (Methods1 and2) was about 13%; forthesamples submergedinaerated water, about 24%; and for the samples storedincore bags, about 25%.

Bobciket al. 175used the imbibition method to comparethe nettability of native-state cores at the wellsite, coresallowed to weather, and cores stored by the two recom-mended metiods discnssed above. The nettability of thecores stored by either of the two recommended methodswas the same as the nettability measured at the wellsite,while most of the weathered cores became more oil-wet.

Am0tt177 used bismethtid”t ocompari”th ewettabihyof native-state cores with similar cores that were exposedtooxygen ayd~owed to partially dry, asshownin Ta-ble 3. The native-stste cores were strongly water-wet, witha dkplacement-by -water ratio of 0.97. In the Amott test,the displacement-by-water ratio is the ratio of the oilvolume displaced by spontaneous imbibition to the totaloil volume displaced by .botb imbibition and forced dis-placement. Itiszero forneuqally mdofl-wetcO~~s aod

J&mal of Petroleum .Tecbnology, October 1986

ly~the displacement-by-oil ratio is zero for neutrally andwater-wetcores aod approaches one as the oil-wetnessincreases. The cores became more oil-wet as they were

either exposed to the air for longer periods of time, o!at higher temperatures. Similar tests on an initially weaklywater-wet core showed elmost no change. On the otherhand, Mungan 115used the imbibition method to meas-ure the wettabilhy of native-state cores. In contrast to tieexperiments discussed above, cores preserved in deaer-ated water were oil-wet, but becsore water-wet when ex-posed to ti for 1 week. Chfingar and Yen35 have alsoreported that some cores became more water-wet on ex-posure to sir, indicating that it is bnpossible to predicthow the wetfsbtity will be altered by tie oxidation of tiecmde.

Mungao 180recnmmendsflushing native-state core withfive erode oil before sny flow studies are startsd. Afternative-state cores .havc been prepared, they are usuallynm at reservoir conditions with crude oil and brine.

Probably the greatest, uncontrollable problem withnstive-state core is the alteration of nettability as the coreis brought m the surface., When the pressure is loweredto atmospheric, light ends are lost from the erode, chang-ing its properties. In addition, heavy components cm comeout of solution and deposit on the rock, making it moreoil-wet. 137 The decrease in temperature wilf alsodecrease the solubili~ of some wettebfli~-altering com-pounds. Pressure coring prevents tie loss of light .erids.However, the cores are frozen before removal, sowetta.bflity-altering compounds ‘W deposit. Unfortunate-ly, there is no experimental work avsilableon wettabfli-ty alteration as the core is brought to the surface. ..

Cleaned Core .’

The second type of core used in core aoalyais is thecleaned core. Cr&ig7 recommends that cleaned core beused for multiphase flow measurements only when thereservoir is known to be strongly water-wet because errorsiq the core am.lysis will be introduced otiimvise. Thereare two main reasons to clean wre. The first is to removeall liquids “fromthe core so that. porosity, permeability,and fluid saturations can be measured. Core cleaning forthese roudoe core measurements will not be consideredin this paper. The second reason for cleaning is to obtaina strongly water-wet core, generally as a first step inrestoring the wettabfity of a contaminated core.

1135

In obtaining a cleaned core, an attempt is made to re-move all of the fluids and adsorbed material, leaving aclean rock surface. Gant aid Anderson 129discuss theme’ibcdsused,tu clean core. One common method is refluxextraction (l)ean-Stark or Soxhfet) with a solvent such astoluene, sometimes followed by extraction with cfdoro-form or methanol. Alternatively, a flow-through systemwhere the solvents are injected under pressure is some-times used. 57,&,65lf the cleaning procedure is success-ful, the core is left strongly water-wet. Cuiec”$5 midothers 57,1w discussed the chemicalreactions involved inthe cleanin process.

Cui&ca,& compared me efficiency of different solventsin flow-through core cleaning. Initially water-wet outcropsandstone and limestone cores were saturated with differ-ent cntdes (sometimes the cores also contained brine), thenaged. The aged cores ivere ncyrmfly neutr~- to oil-wet,as determined. by the Amott wettabflity test. The coreswere then cletied with dlffererit solvents, and the Amotttest was used to determine cleauing efficiency. Cuiecfound that he could clean both sandstone and liiestonecores by flowing the f?ll@ig seven solvents through thecore: pdarte, hexane, heptane, cyclobexane, beuzene,pyridine, and ethanol. Chloroform, tohtene, and methanolused singly were not very effective. Cuiec also lookedat several dtiercnt acidic and basic solvents used individu-ally and found that the acidic solvents tended to be moreeffective in cleaning sandstone, whiie the basic solventswere better in cleaning Iimcstone. This difference was at-tributed to the acidic nature of the sandstone surface andthe basic mture of the limestone surface. For exampleibecause sandstone (silica) has a weakly acidic surface,it tends to adsorb bases from tie crude oif. When astronger acid flows through the sys@m, it will graduallyreact with and strip off the adsorbed bases, Ieaviug a cleansilica surface.

G@ and Anderson 129 surveyed most of the core-cleouing experiments in “the literature. They found thatthe best choice of solvents depends heavily on the cmde~d the mineral surfaces becavse they help determine theamount and @pe of nettability-altering compounds ad-sorbed. Solvents that give good results with some coresand cmdes often faif in other cases. For example, Gristet al. 1s4 and Holbrook and Beruard45 both found thatthey could clean core to a strongly water-wet state usinga cliloroformfmerhanol mixture, while Jennings5s repOrt-ed. fiat thk was unsuccessful. For cleaning for routinecore analysis, API 1s5 reports that cbfom form is excel-lent for many midcontinent .ct’udes,wh~e toluene is us6-ful for asphaltic cntd:s..

hi many cases, it appears that any single solvencis rela-tively ineffective in core cleaning and that much betterresults can be obtained wiih a mixtttfe or series ofsolvents. 129 The followhg solvents have, been rCpOfi-ed for specflc binbinations of crude and core to givepcor resufts when used alone: chloroform, ‘,65 ben-zene, 5S,1M,120~=bon di~~fide, lU,120 ~~mol, @ ~d

toluene.5@.@.65.1~.120,1T.l~,1s6Many of the researchers cited above have found that

toluene used alone is one of the least effective solvents.However, when combined with other solvents, such asmethanol (CHs OH) 184 or ethanol (CH3 CH zOH), 61toluene is often ve~ effective. The toluene is effectivein removing the hydrocarbons, including asphal-

tenes 130JWand some of the weakly polar compcmmi.s,lWwbile”tbemore,spongly ’polar methanol (ethanol) qcmovesthe strongly adsorbed polar compounds that are oftenresponsible for altering wettabilky. In addition totoluenelmethanol and tolueneletbonol, successful clean-ing has ako been reported with cbforoforndace-tone 1wZ120.1= and cfdorofordmetfranol, 1s4 as well asa number of different series of solvents. ‘,65

CuieCand his coworkers made the most extensive studyof core cleaning for nettability restoration. In a recentpaper, Cuiec et az. 130statkd that their core cleaning al-ways begins with a toluene flush to remove hydrocarbonsand asphaltenes. A number of solvents are then.tested todetermine the most effective, including (1) a series of non-polar solvents, e.g., cyclohexane or heptane; (2) acidicsolvents, e.g., cblorofonn, ethanol, or metbanoh (3) ba-sic solvent’i, e.g., dioxane or pyridine; ond (4) mixturesof solvents, e.g., methanollacetoneltoluene. When noneof these procedures are effective, other tests are performedby combining the above procedural, using otler solvents,ad incremfig the Circdatiog time.’

Tohtene is generally not a very effective solvent, butit can”alter the nettability of some core. Jennings 186cleaned sever,d cores by toluene extraction and found thatthe wettabilities and relative penn.eabilities were notchanged. He stoted that this indicated that toluene-extmcted core retoined the reservoir wettabi!ity and coufdbe used for relative p+mneabtity rneosurements, However,this generally is not the case. Aftbough it is less et%cientthan other solvents, we have found that toluene extrac-tion can alter the wettabili@ and relative penneabtiticsof native-state core. fn some cases, neutmlly wet or tidlyoil-wet mtive-state core becomes strongly water-wet ti-ter extraction witi toluene. The relative permeabilitycume~ ~~o ~E,fi. AMOU177 ako found that toluene ex-traction can clean some cores, while it had Wt3eeffectfor other ones, such as the strongly oil-wet Bradford cores.Therefore, because tolueneextraction will alter the wet-tabilky and relative permeability of many. native-statecores, m%uremcnts shouId be tie on mtive-state coresbefore toluene extinction.

One problem with a cleaned core is that it is sometimesdifficult, if not impossible, to remove all of the adsorbedmaterial. If this occurs, the wetta.bfity of tie cleaned corewifl be left in some indefinite staie, causing variations incore analyses. Grist et al. lW cleaned cores by three cu-rently used methods and then examined how ROS and end-point effective permeabilities vtied after a waterflood.ROS was very similar for W methods. However, the end-point effectiye water permeability varied by more thana factor of three betwtin different cleaning methods. Theirexplanation for this behavior was that some methods wereable to extract more of the adsorbd. components, leav-ing.the rock more water-wet. In the more water-wet cores,the rwidti oil had a greater tendency to form trappeddroplets, blocking pore throats and lowering water per-meabtity. The least effective of the three cleaniug me~odswas overnight reflux extinction with toluene. More ef-fective was reflux extraction with toluene followed by 2days of extraction with a mixture of cbloroforin oudmethanol. Finally, tie most efficient method was refluxextraction with tcduene followed by 3 weeks of extrac-tion with chloroform and methanol. In the last stage ofcleaning, methanol was used alone.

1136 Journalof PetroleumTechnology,October1986

Another draivback of cleaned cores is that it is occas-sionafly possible for cIeaning to change an originallywater-wet rock to an ofi-wet one. The extraction processmay quickfy boil off the connate water, allowing the re-maining oif to contact the rock surface and form oil-wetdeposits that are afmost impossible to remove. 187

The cleaning experiments discussed examine the bestmethods to remove. cmde oil constituents from the porewalk. In many cases, core is also contaminated with drill-ing mud surfactits, which “mustalso be removed beforethe wettabifity of a“core can be restored. 12ar129The bestchoice of solvents depends on the crude, the mineraf s~r-faces, and the drilfiig mud surfactsnts. Gant andAnderson 129cleaned Berea sandstone and Guelph (Bak-er) dolomite plugs contaminated with an invert-oil-emufsion rfrifling mud. filtrate. The best solvent fOr bOfhrock types was a 50/50 mixture of toluene/methanol, oithe equivalent, containing 1% ammonium hydroxide. Athree-step method (three successive Dean-Starkextractions-toluene, foffowed by glacial acetic acid, fol-lowed by ethanol) was the second best choice for Berea,while 2-methoxyetiyl ether was the second best choicefor dolomite, demonstrating that the choice of solventscan depend O? the mineral surfaces in the core.

Restored-State Core, If one conld be “positivethat the original reservoir wetta-

bilhy had”izotbeen inadvertently modified, a native-statecore would give resnks closest to those of the reservoir.However, riative-st@ecores present scveraf problems. Thenecessary procedures to preserve the wettabtiq’ aretroublesome and time-consuming. Even when sll of theprecautions iwe tsken, there is still a possibility that thenettability has been chtiged through oxidation or throughdeposition as ‘tie temperature and pressure dropped whenthe core was brought to the surface. In addition, tic ques-tion ‘arisesabout tie procedure to follow to obtah the mostreliable information from cores in which the nettabilityWaS aftered

When onfy core with alt&ed wei@bfity is available,the best possible mukiphase measurements ore obtainedby resto& the resefioir wettabfi~ with a three-step

F~roces~.47, 0,64,65.,96,115,128,130,1S0,18SThe f~st ste~ is to

~leaa the core to rernoVe’all compounds from th~ rocksurface. After the core is cleaned, the second step is toflow reservoir fluids into the core sequentially. F~y,the core is aged at the reservoir temperamre for a suKL-cient dine b establish adsorption equilibrium. Seversl ex-perimenters have compared measurements made on corein the native, cleaned, and rsatored states. In each experi-ment, measurements in the restored state were slmostidentical to the,previous mtive-sta.te “ones,demons@atinthat this procedure will restore nettability. 50,115Js0;18~

~,, The first and most @fficult step in nettability restora-tion is to clean the contaminated core by use of themethods described to remove all compounds adsorbed onthe surfaces and to make the core as water-wet as possi-ble. All compounds must be removed from the core be-cause we have no knowledge of which compounds wereadsorbed on the undisturbed reservoir rock and whichwere deposited afterward. The USBM or Amott netta-bility measurements are used to verify that the core isstrongly water-wet., Unforttzmtely, detemining which sol-vent wiII successfoffy clean the core is still a trial-and-

Fig. 1—Wettabitity changes for a restored-state core andthe effects of flushing restored-state cores with refinedOIIS. Berea core and Big Muddy crude.

error process because the best choice of solvents dependsheavily on the crude oil, the mineraf surfaces, and any&idling mud contaminant. Further discussion can be’found”in Ref. 129.

In the second step, sequentially flowing reservoir fftidsbtto the core, the core is saturated with deoxygenated syn-thetic or formation brine and then flooded with crnde oilto simnla.tsthe intlow of oil into the resemoir. When cmdeoil for wettahifity restoration is obtained, precautionsshould be taken to minimize alterations to the crude. Thehnple must be taken before tiy Sm&ct.mrts or Ofierchemicals ae added to treat the crude. It should be takenas Iong as possibIe after any wefl treatments to aIIow timefor these chemicafs to be flushed from the well. Finally,the cmde should be sealed in air:tight containers as soonas possible to minimize oxidation and the 10SS of light.ends.

The fired step in wettsbfity restoration is to age tie coreat the reservoir temperature for a stilcient time to es-tablish adso~tion e&libzium. The aging time requiredto re-eatabfish reservoir nettability varies, depending onthe crude, brine, and reservoir rock. Generally, we feel&at core shoufd be aged for 1,000 hours (40 days) at thereservoir temperature. 128This a&ng period was chrken

for two reasons several experiments have shown that upto 1,000 hours is required to reach wetting equilibri-um ~$s. 115,189-lgl and 1,000 hours is roughly the lengthof ~me required for the contact ~gle measnred on a flatsurface to approach its equilibrium value. 7>26,34.191IIIsome cases, the restoration time can be significantly lessthan l,OW hours. MunganlsO was able to restore the wet-tabilky after aging for 6 days, while the nettability of therocfuoilh’ine system used by Schmid50 and Riibl et~. lss was restord after only 3 days. Salathie147was ableto restore a mixed-wettabilhy qate to samples after 3 days.Cuiec et al. 130describes two reservoirs in which the wet-tabtity was restored after only a few hours, with no fur, <ther cbamgesin tie wettabiIity for aging times as long as1,000 ho;rs.

There are two basic options to determine the aging timeto restore wettabllitv. We feel that it is ,most convenientto age afl cores for l:W” hours, which is roughly the mm-imum time that the experiments discussed previously re-quired to achieve wetting equilibrium. While cores may

Iourmt of Petroleum Technology, October 1986 1137

be aged for a period longer than the minimum necessary,thk is not a serious drawback because the aging cores re-quire minimal attention. Another possibtity is to deter-mine the minizhtzmaging time by measuring the wetrabfityof the core with the USBM or Amen methods at frequentintervals during the aging period. The aging is stoppedwhen the wettabflity reaches its cquilibtium value.Although this minimizes aging time, it is much less con-venient because it is labor intensive nnd requires frequentdisturbances to the plug.

The core is aged at either the reservoir pressure withlive cmdeso, 180,188,191or ambient pressure with deadcmde. 115.128.190 When live crude oils a~d the reservoirpressure are used, the solubflities of the wettabilhy-altering compounds should have their reservoir values.It is possible that the nettability will differ when deadcmdes .atnmblent pressure are used. At the present time,however; it is not known whether the difference is im-portazm

Fig. 1 shows the chsnges in the USBM wettabfity in-dex as a core was restored. * A series of Berea plugs wassaturated with brine and driven to IWS by centrifugationin crude oil. Each core was aged in dead crude for a differ-

ent period, of time, after which the USBM wettabtity wasmeasured. As can be seen, the wettabilky changed fromwater-wet (W =0.8) to moderately oil-wet ( W= – O.3)over a 40-day period. The plugs flushed with Soltrol@and Blnndol@ will be dkcussed later.

Lorcnzetal. 190and Cuiec65 found tbatitissometknespossible to speed up the approach to wetting equilibriumby saturating.thecore with oil alone. The approach toequilibrium is fastix’ because the polar compounds nolonger have to dlffase across a water layer to adsorb onthe rock. This procedure should be avoided, however, be-cause it can give iriaccuratc results. For example, con-sider the restoration of a core that originally hadSalatbiel’s47 mixed wettab~ity, where &e large pores areoil-wet nndthesma!.l ones are water-wet. During tbeag-ing process, thesmall pores must contain comate.waterto prevent the deposition of au oil-wet fiim, leaving themwater-wet. Onthe other hand, ifaclcan core is saturatedonly with oil, tbe entire core, includlu gtbesmallpores,will become uniforndy oil-wet, whlchis the wrong wet-tability. Anaddhionalp roblemw ithsaturadngt iec oresolely with oil istbat the effects of brine chemistry areignored. As discussed previously, the wettabtity of thecore depends on the ionic composition and pH of the brine.Finally, Clementz10?.120,121$howedtbat flowing cntdeoiltbrougha dry core camcause tbeformition of verystable oil-wet, claylorganic complexes. Thepresenceofan initial water film on the clay surfaces haa been shownto reduce but not completely inhibit the adsorption of thenettability-akering materkds. @@.70 The effects of brineOtI wearability make it necesssry to saturate the core with

brine, then oil, during the nettability restoration process.

Experimental ConditionsOnce a mtive or restored-state core is obtained, core anal-yses can be performed. These tests can be mn with eithercrude or refined oil at ambient or reservok’ temperatureand pressure. Because wettabfity effects are being ig-

‘Personalc.mm””lcati.nwl,hD..J.Wendel,Pe!r.aleumTestingSeMceS,SmtaFeSPringS,CA,No”.19S0.

nored, cleaned cores are generally mn with refined oif(or even mercury or air) at room temperature and pres-sure. From the viewpoint of titaining the nettability,the best laboratory tests should be mn with native or re-stored cores at reservoir conditions with live cntde oil andbrine because this is the best simulation of reservoir con-ditions possible. Cor~ are generally more water-wet .atrese~oir conditions tbzn they are at rooin temperaturead pressure, 62,180,192-195The effects of the followingexperimental conditions on nettability will be dkcussed:(1) rcaervoir vs. room temperature, (2) live vs. &ad cmdeat reservoir pressure, and (3) refined vs. crude oils.

Changing the temperature has two different effects, bothof wtich tend to make the core mom water-wet at highertemperamres. First, an increase in temperature tends toincrease the solubtity of wettabtity-altering cOm-pounds. 196 some of ~eSe compounds will even desorb

from the surface as the temperature increases. Second,the IFT and the contact angle measured through “-bewaterwill decreaae as the temperate increases. This effect hasbeen noted in experiments with cleaned cores, minernloil, and brine, where it was found that cores at highertemperatures were more water-wet even though therewere no compounds that could adsorb and desorb. 19-2?For example, McCaffery201 measured the water-advancing contact angle on qWrtz of n-tetradecane andbrine. The amglewas about 40° [0.7 rad] at 77°F [25”C],but decreased to about 15°. [0.3 rad] as the temperaturewas raised to 300”F [150” C].

when live crude oils at the reservoir pressure and tem-perature are used, the solubilities of.dzewettabfity-aftetingcompounds have their reservoir values. The use of deadcrude at ambient or reservoir prcasure may change thenettability kmzse the properties of the crude are altered.Light ends are lost from the crude, while the heavy endsare, less soluble, which may make the core more oil-wet.However, the effects of pressure are not known at pres-ent. The two reported experiments found that ressureis much less important than temperature. 18~,1~ Hje~.

meland and Lamondo 192found little difference in con-tact angles measured using stock-tank vs. live cmde atthe reservoir temperature (190”F 88”C]) and pressure

i(3,800 psi [26.2 MPa]). Mtmgan 10 measured a water-advancing contact angle ,of $7” [1.5 rad] using live reser-voir crude and synthetic formation brine at resemok tem-perikurc (138”F [59”C]) and pressure (1,200, psi [g.3MPa]). The water-advwcing contact angle was almostidentical, 85” [1.48 rad], using degassed crude and brineat ambient pressure and reservoir temperamre.

Because refined oifs are much easier to work with tlumcmde, it is a common laboratory practice to flush native-or restored-state cores with refined oil before testing.However, there is a possibilky that this idters the netta-bility. Craig7 poshdated that it would be possible, oncethe original wettabtity was restored, to use refined nzin-eml oil in place of crude oil in laboratory tests withoutadversely affecting the wetk+bility. Test times are shor!compared with the time it takes to achieve adsorption equi-librium and obtain native wettsbtity (about 1,000 hours).Craig hypothesized that the desorption of wettability-Mbzencing materials would require a correspondinglylong period of time. If this is correct, @e orig@l wetta-btity wotdd be unchanged if laboratory tests using refinedoil and brine were conducted quickly enough.

1138 Journal of PetroleumTechnology,October1986

The onfy experinient to teat this hypothesis that we areaware of was conducted by Wendel. * He aged ,Blg Mud-dy crude in Berea sandstone at IWS to develop hisrestorer-state cores. The cores. were flushed with one oftwo refinkdoik, Soltrol 170 or Bkmdol, to detexmine howthey affected the wettabfily. The results&e show in Fig.1. Bkmdol did not si@ficantly affect the we~btity, whileSoltml 170 changed tbe core from oil-wetto neutrally wet.The wettabdity: alteration could be caused by eithersurface-atilve impurities in the Soltrol 175or desorptionof previously depositwj oti-wetdng crude compounds fromthe pore walls into tie Soltrol. It i; not known which ex-planation is correct. Wendel did not attempt to fflter therefined oils tfmugh a cbromatogmphic coltmm tn removesurface-active compounds. These contamiim ts are knownto have a large effect on corit.w-migle measurements,which are extremely seyitive to small amounts of con-taminants. Wettabifity measurements in core should beless sensitive, however, because the ratio of smface areato volume is “much higher.

Conc133sioris1. The nettability of a rsaeryoir ample affects ita capil-

lmy pressure, relative pe,rmwbtity, waterflood behavior,dispersion, mid electrical properties. fn addhion, simu-lated teftiary recovery can be 51ter,cd.The tcfi,~ recov-e~ PrOcesses affected by we~biE~ include hot-water,surfactant, miscible, aid caustm floodlng.

2. Cleaned, strongly water-wet cores should be usedonfy in such c6re analyses as porosity. and air permeabil-ity, where the wettabilky is unhpportmrt. h addition, theymay be used in other tests when the reservoir is knownto be strongly water-wet.

3. The nettability of originally water-wet mineral sgr-faces can be altered by the adsorption of pokw compoundsaui/or the deposition of orgariic rnatter””tlmtwas origi-MUY in the crude oil. Fmrfactants in the crude oil aregenerally believed to ,be polar compounds that containoxygen, nitrogen, ,mdlor sulfur. These compounds ~most prevalent in the heavier fractions of crude oil, suchas the resins and asphaltenes.

4. Nettability alteration is determined by the interac-tion of the oil constituents, the mineral surface, and thebrine chemistfy, including ionic composition and pH. InsiIicafoiVbrine systems, trace amounts of mukivalent me-M. cations can alter *e nettability. The catiom can reducethe solubti~ of crude oil surfactants and/or activate theadsorption of aniotiic surfactants onto the silks. Mfdtiva-lent ions :$tathave altered tie wettabfity of sihcafoil/brinesystems tnclude Ca’2, .Mg’2, Cu’2, Ni’2, and Fe’3.

5. Work on mineral flotation indicatca that coal,graphite, sulfur, ‘talc, the talc-liie silicates, and many sul-tidca are probably naturally,neutrally wet to oil-wet. Mostother minerals-includhg quartz, carbonates, andsulfates—are strongly water-wet in their natural s@.te.

6. Contact-angle measurements suggest ti.at most car-bonate reservoirs range frpm neutralIy to oil-wet as a re-sult of the adsorption of surfactimts from the crude oil.

7. Very little work has been reported about the changesin wetibility caused by drioiig mud addhives. Threedifferent “Cciring.flrtidshave been recommended to obtainnative-state core: (1) synthetic formation brine, (2) un-

-PemmalmmmunlcatimwilhD,J.Wend.at,PetroleumTestingS6wkeS,SantaFe SP,ingS,GA,N.”. 19S0,

oxidized lease crude oil, or (3) a water-based mud witha minimum of iddkives. B&use of surfactits in the SYS-tern, no conimercitiy available oil-based or oil-ernukionmuds are khown that preserve the native wt?ttability.

8. The wetr?bility of a native-state core. cambe alteredby loss of light ,ends and/or the deposition aid oxidationof heayy ends. TWOalternative pac@ging procedures cambe used to miniinize these effects. The first is to immersethe corei in deoxygenatdd formation or synthetic brineand place !hem in a glass-lined steel or plastic tube, whichis then seaIed against leakage aud the entrance of oxy-gen. An alteinaiive procedure is to wrap the cores at thewelksite in polyethylene or pglyvinylidene fdm and tien.‘in ihunirimn foil. The wrapped pore is tlyn coated withi+thick layer of paraffin or a plastic sealer.

9. Because of the increased solublky of the wettability-altering compounds at the higher temperature spd pres-sure, the cmde-odtbrinetcore system is usually more

water-wet at reservoir condition than at ambient con&-tions. In addition, the contact angle measured tluough thewater will generslly decrease as the tempetatufe is in-creased, and the system will become more water-wet,even if no surfactauts are present.

10. Extraction with toluene cti alter the wettabil.ity ofsome iiative-state cores, causing some”initially neutrallywet or qikfly oil-wet cores to become strongly water-wet.Measurements on native-state iorei should be made be-fore toluene extraction.

11. During the attempted restoration of a cleaned coreto ita orig$al wetrabtity, the core should be saturated withbrine, @lflooded, md then aged at the reservoir corrdi-tiom for 1,COOhours. This will embie a inixed-wettabtitycondhkin to be restored, if thk was the original wettabd-ity. In addition, it will allow the brine chemistry to influ-ence tie r~tored nettability. An alternative procedure,which completely saruratea the core with cmde oil, should,be avoided.,

12. The three commonly used methods for artificiallyconrrolEng wettabfity during laboratory experiments are(1) treatment of the core with chemicals, generally or-ghocblorosilane solutions for sandstone. cores andnaphtbenic acids for carbonate cores; (2) using sinteredteflon cores with pure fluids; and (3) adding surfacmntsto the fluids. To obtain a uniformly wetted core, a sin-teredteflon core with pure fluids is preferred because itsnettability is more constant and re reducible than the wet-

#tabilby of cores treated WI organochlorosilanes,naphthenic acids, or smfactants. However, these treat-ments have advantages when heterogeneous wettabllityor nettability alteration is”studied.

AcknowledgmentsI w grateful to Jeff Meyers for hk many helpful sugges-tions and comments. I also thank the management ofConoco h.c. for permission to publish this paper,

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1144 Jomtiof Pewoleum Te&”olo~, October 1986