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Wettability Alteration in Gas-CondensateReservoirs To Mitigate Well Deliverability

Loss by Water BlockingMyeong Noh* and Abbas Firoozabadi, RERI

SummaryLiquid blocking in some gas-condensate reservoirs is a seriousproblem when the permeability is low (for example, of the order of10 md or less). The current practice centers mainly on hydraulicfracturing to improve gas flow. In most cases, the frequency ofapplication results in high costs. An alternative is the permanentalteration of wettability from liquid-wetting to preferentially gas-wetting. In this work, we present an experimental study of wetta-bility alteration to preferential gas-wetting using a multifunctionalsurfactant and polymer synthesized for this particular application.The treatments are performed with an alcohol-based-surfactant/polymer solution. We treat Berea cores and reservoir-rock samplesfrom two gas-condensate reservoirs. In one of the reservoirs, waterblocking has resulted in a significant reduction of well deliverabil-ity. The treatment provides significant improvement on the phasemobility. In this study, our focus is the investigation of water/gastwo-phase flow at high temperatures (80 and 140°C).

Basic measurements such as contact angle, spontaneous imbi-bition, and the effect on the absolute permeability are discussed.The initial liquid saturation at the time of treatment may have aninfluence on the wettability alteration. The results of the treatmenton oil-saturated and water-saturated cores are presented. The treat-ment by alcohol without using the polymer is compared and dis-cussed. Two-phase-flow tests in single-phase and two-phase in-jections are performed before and after the treatment using brineand gas. Relative permeabilities of gas and water are measured,and the improvement after the treatment is presented. Variousmeasurements in our work show that water and gas relative per-meability increase significantly in a wide range, especially at highliquid saturation.

IntroductionThe exploitation of low-permeability gas-condensate reservoirshas received increased emphasis in recent years. Liquid trapping(water or condensate blocking) around a wellbore is one of themajor causes of reduced productivity in low-permeability gas-condensate reservoirs. Formation damage by the loss of aqueousfluids by operations such as drilling, fracturing, or acidizing is apotential source of reduced productivity of gas reservoirs becauseit causes water accumulation (water blocking) near the wellbore.

Water blocking is caused by capillary pressure, which tends toimbibe and hold the liquid phase, resulting in a reduction of gasmobility. The decrease in water saturation from hydraulic fractur-ing around the wellbore is a slow process when the permeability islow and the capillary forces are high. The investigation of thegas/water relative permeabilities can determine the gas-mobilityloss associated with the change of water saturation.

Early studies by McLeod and Coulter (1966), and McLeodet al. (1966) showed that the alcoholic acid mixture of isopropylalcohol, or methanol, and hydrofluoric acid/hydrochloric acid (HF-HCl) helps the water-removal and cleanup rate in gas wells. Theytested various compositions of the acid mixture, including alcohol;

the treatment improved the displacement of the fluid by decreasingthe interfacial tension and increasing water vaporization in gasreservoirs, particularly those with high clay content. They alsosuggested that the alcohol treatment would be more effective in ahigh-pressure and -temperature reservoir because of lower inter-facial tension.

Poor gas production in low-permeability reservoirs after appli-cation of hydraulic fracturing is discussed in many papers (Tan-nich 1975; Liao and Lee 1993; Abrams and Vinegar 1985). Liquidinvasion and leakoff during this operation can reduce well produc-tivity. Tannich (1975) showed that the cleanup of water blockingis fast when the fracture conductivity is very high. Therefore, wecan expect rapid cleanup when the reservoir is highly permeablebecause the capillary pressure tends to be small. Liao and Lee(1993) presented numerical studies of liquid cleanup and gas-production performance for hydraulically fractured gas wells.They showed that the parameters for water blocking and cleanupare capillary pressure and relative permeability. When the reser-voir rock is damaged by fracturing-fluid invasion, the pressuredrop should be large enough to overcome the capillary end effectof the damaged zone at the fracture surface. Abrams and Vinegar(1985) used the capillary entry pressure to estimate the pressuredrop required to initiate and maintain the gas flow into a brine-saturated core. On the basis of their work, Abrams and Vinegarconcluded that the pressure drawdown has to be much higher thanthe capillary entry pressure to avoid significant water blocking.

Cimolai et al. (1993) and Bennion et al. (1993) presented core-flood studies demonstrating that reservoirs with low initial watersaturation readily accommodate the invaded water. They suggestedthat the improvement and reuse of drilling fluids can improvehorizontal-well performance markedly by minimizing formationdamage. Kamath and Laroche (2003) discussed the cleanup ofwater blocking in gas wells based on two regimes: (1) displace-ment of the fluids from the formation followed by (2) vaporizationof water by the flowing gas. The second regime gives slow dis-placement, and the deliverability slowly increases during severalmonths. Even if the flowing gas is fully saturated with water, watersaturation can be reduced because the gas becomes undersaturatedas the pressure decreases. They suggested that the conventionallaboratory data exaggerate the deliverability loss caused by waterblocking and that the alcohol treatment can improve the recoverysignificantly. Mahadevan and Sharma (2003) studied the effect ofpermeability, wettability, temperature, and surfactants on thecleanup of water blocking. The evaporation regime lasted for thou-sands of pore volumes (PV) of gas flow resulting in a slow cleanupand improvement in gas relative permeability. Mahadevan andSharma (2003) suggested that the cleanup of water blocking can beimproved by

• addition of solvent (methanol) to increase the vaporization rate• increase of permeability• change of wettability of the rock from water-wet to oil-wet

by introducing surfactant• increase in temperature• increase in drawdown

Wettability alteration to intermediate gas-wetting in porous mediaby treatment with a fluorochemical polymer has been establishedby researchers at RERI (Li and Firoozabadi 1979; Tang andFiroozabadi 2002, 2003). Tang and Firoozabadi (2002) measuredthe relative permeability before and after the treatment for Berea

* Currently with Chevron Corporation.

Copyright © 2008 Society of Petroleum Engineers

Original SPE manuscript received for review 1 June 2005. Revised manuscript received forreview 17 March 2008. Paper (SPE 98375) peer approved 19 March 2008.

676 August 2008 SPE Reservoir Evaluation & Engineering

sandstone using the fluorochemical polymer, FC-722. In mostcases, the treatment increases the endpoint relative permeability ofthe liquid phase and decreases the irreducible liquid saturation andendpoint gas relative permeability. As a result, liquid mobilityincreases, while in some cases, there may be a reduction in gasrelative permeability. But even when there is a reduction in gasrelative permeability, because of the substantial increase in liquidrelative permeability, the treatment results in an increase of gas-flow rate for a given pressure drop, as will be shown later inthis paper.

The effect of the chemical treatment may depend on manyfactors, including initial fluid saturations, type of rock, reservoirtemperature, and, most importantly, the type and composition ofthe chemical additives. The main purpose of this work is the studyof chemical additives for two reservoir rocks to quantify the im-provement of gas mobility after the treatment.

Since the recent studies (Li and Firoozabadi 1979; Tang andFiroozabadi 2002, 2003), we have tested new chemicals in differ-ent types of core samples. In this paper, we present experimentalresults using the Fluorochemical Surfactant 11-12P and the Fluo-roacrylate Copolymer L-19062. We use sandstone-core plugs fromtwo different gas-condensate reservoirs and Berea cores. In thefirst set of experiments, we examine the effectiveness of thechemical additive on a particular rock type by measuring contactangle and spontaneous imbibition. Thereafter, we perform variousflow tests with different chemical concentrations. In this paper, weshow that the wettability of reservoir cores can be altered fromoil-wetting to preferentially gas-wetting state. The results from theflow tests demonstrate the effectiveness of wettability alterationfrom improved gas flow in gas-water systems at 140 and 80°C.

Fluids and RocksBrine (1.0 wt% of NaCl) and nitrogen are used as aqueous andgaseous phases, respectively, in the experiments. Density and vis-cosity of brine are 1.0 g/cm3 and 0.97 cp at 20°C. Gravity of purenitrogen gas is 0.967. The interfacial tension between gas andwater is 71 dyne/cm at the ambient condition. For the oleic phase,normal decane (nC10) is used. Specific gravity of nC10 is 0.73. Inthe past, we have compared imbibition- and flow-test results ofnC10,nC14, and actual condensates. Results were comparable.

We tested six Berea, and eight reservoir cores from two dif-ferent gas-condensate reservoirs; the relevant properties are shownin Table 1. Some of the absolute-permeability data were measured

by outside laboratories, and they are compared to our measure-ments. For some cases, a reduction in absolute permeabilities isdetected after the treatment. A procedure to minimize the reductionof permeability has been devised. The results will be discussed inthis work.

High velocity coefficients are calculated by plotting gas-flowrates and pressure data. The absolute permeability and high-velocity coefficients are calculated using (Katz 1959; Firoozabadiand Katz 1979)

�p12 − p2

2�M

2�ZRTL�W�A�=

1

k+

�

��W�A�. . . . . . . . . . . . . . . . . . . . . . . . . . (1)

Here p1 and p2 are the inlet and outlet pressure, respectively; Mand � are molecular weight and viscosity of gas, respectively; W/Arepresents mass flux; k is the absolute permeability; R and Z are thegas constant and the gas deviation factor, respectively; T is tem-perature; and L is the length of the core. High-velocity coefficients� may increase after the treatment; that is consistent with perme-ability reduction. For permeability measurements, we use outletpressure higher than 50 psi to reduce the Klinkenberg effect.

ApparatusSingle-phase-water- and two-phase-injection tests in gas-saturatedcores are performed to show the mobility improvement after thetreatment. Fig. 1 shows a schematic of the experimental setup. Acore holder is placed in an oven horizontally. Gas injection iscontrolled by a pressure regulator. Water is injected with a con-stant flow rate, and gas-flow rate is measured at the outlet.

Fevang and Whitson (1996) suggested an experimental tech-nique for measuring krg as a function of krg/kro. Two-phase relativepermeability experiments were proposed using the pseudosteady-state technique to measure relative permeabilities under conditionsthat are similar to the near-well region of a gas-condensate reser-voir (Mott et al. 2000; Cable et al. 1999). They showed that theupper limit of krg/kro is approximately 10 for rich condensates andapproximately 50 for lean condensates. An upper limit of 50 ap-plies to practically all gas-condensate reservoirs because krg isrelatively high at krg/kro>50 and the extrapolation to higher krg/kro

is straightforward. Therefore, condensate blocking depends onlyon relative permeabilities within the range of 1<krg/kro<50, andthis range represents approximately 0.05<krg or kro<0.3. Here wemeasure the relative permeability using nitrogen/water two-phaseflow focusing on 1<krg/krw<100. For two-phase-injection tests, we

677August 2008 SPE Reservoir Evaluation & Engineering

inject water for 20 PV to saturate the core and then inject water andgas simultaneously. Water- and gas-flow rates are recorded atsteady state. Next, we decrease the water-flow rate and repeat themeasurements to obtain drainage relative permeability data.

Darcy’s law is applied to calculate water relative permeability.For gas relative permeability, however, the high velocity coeffi-cient from single-phase gas flow may not be valid in two-phaseflow because it can be affected by the presence of a second phase.The reduction of effective porosity and the increase in effectivetortuosity results in higher effective resistance when water ispresent. Some authors (Liu et al. 1995; Frederick and Graves 1994;Ali et al. 1997) include the relative resistance change in the pres-ence of the second phase. Here we follow the correlation by Liuet al. (1995) and use the two-phase/single-phase ratio high-velocitycoefficient given by �rg�krg

−1. The two-phase high velocity co-efficient can be written as

�2� = �1��rg =�1�

krg. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2)

Combining Eqs. 1 and 2, we obtain the expression for gas-phaserelative permeability:

krg = �1

k+ �1�

W�A

�� p1

2 − p22�M

2�ZRTL�W�A��−1

. . . . . . . . . . . . . . . . (3)

TreatmentWe present the basic evidence of wettability alteration after thetreatment. Fluorochemical Surfactant 11-12P is used to alter thewettability of core plugs to preferentially gas-wetting. We also useFluoroacrylate Copolymer L-19062. We have tested two differentbatches of 11-12P. For convenience, the first batch and the secondbatch are named 11-12Pa and 11-12Pb, respectively. Contact-angle measurements, spontaneous-imbibition tests, and the effectof the treatment on absolute permeability are discussed.

Procedure and Adsorption. In this section, we first present theprocedure for treatment for Core C411. Then we provide data forall the other cores. Core C411 is placed in an oven at 140°C. Thealcohol-based solution with 11-12Pb is injected for 5 PV at 200psig. The solution used in the treatment for this core consists of83% ethanol, 10% water, 3% acetic acid, and 4% 11-12Pb. Thesurfactant solution has only 2% 11-12Pb; the rest of the 98% is thesolvent (ethanol).

The core is aged overnight (15 hours) at 200 psig and 140°C.Thereafter, we inject 100 PV of water to find out if the waterinjection washes out the surfactant adsorbed on the pore surface.The adsorption after washing with water is calculated using theweight difference before and after the treatment:

C =weight increase after treatment

weight after treatment

= �mg of chemical⁄g of core�. . . . . . . . . . . . . . . . . . . . . . . . . (4)

Unlike Core C411, which is treated with 4-wt%-surfactant solu-tion, Core H122 is treated with 2 wt% of 11-12Pb. The adsorptionis 1.6 and 0.53 mg/g for Cores C411 and H122, respectively. CoreO319 is treated with 4% 11-12Pa, and the adsorption is 0.24 mg/g.Chemical L-19062 is used in the treatment of core plugs H131,H113, and C422. The adsorption results are summarized in Table2. Generally, the treatment with high concentration results in ahigher adsorption; also, the tighter the core, the lower the adsorption.

A small permeability reduction is expected because of the ad-sorption of the chemical onto the pore surface. However, in somecases, there is a significant reduction in permeability because ofextensive chemical adsorption in the inlet part before the solutionspreads throughout the core. The result is a significant reduction ofpermeability. The pretreatment procedure is applied before thechemical injection. The pretreatment solution consists of water,acid, and ethanol, and it is injected into a core for 5 PV. Next, weinject 5 PV of various concentrations of L-19062 and ethanol sothat the reaction occurs only in the core. We have recently carried

Fig. 1—Schematic of the apparatus for flow measurements.


out a comprehensive study on the nature and extent of chemicalreaction. Results will be published at a later date. The two-steptreatment procedure is applied in a Berea core with 12% L-19062;there is only 5% reduction of permeability. The concentrations of2 and 4% L-19062 are also applied in tight reservoir cores. Theresults are presented in Table 1. Note that with the pretreatment,there is little change in permeability.

Contact Angle. We perform a simple test to determine the wetta-bility of samples. When a drop of nC10 is placed on the untreatedCore H122, immediate imbibition occurs and the drop becomesinvisible rapidly (Fig. 2a). However, the water drop stays on theuntreated sample and forms a contact angle of approximately 90°.Therefore, the untreated core sample is strongly oil-wetting. Afterthe treatment with 2% 11-12Pb solution, the contact angles ofwater and nC10 change, as shown in Fig. 2b. The water drop formsa contact angle at approximately 150°, and nC10 drop shows acontact angle of approximately 60°. The results in Core O319show a smaller contact angle (20°) for water before the treatment;after the treatment with 4% 11-12Pb, the results are similar tothose of Core H122 (Fig. 2d). Core C411 behaves similarly. 4%treatment with L-19062 in Core C422 shows similar water contactangle, but nC10 imbibes slowly, as shown in Fig. 2f. Visual ob-

servation shows that the wettability of the core sample is alteredafter the treatment, but there is little difference in contact anglewith respect to the chemical concentration (see Figs. 2b and d).

Spontaneous Imbibition. To quantify the wettability change of acore sample, we use the spontaneous-imbibition tests with waterand nC10 at ambient conditions. The air-saturated core is immersedin the liquid, and the weight is recorded throughout the test. Fig.3 shows that water and oil saturations in the untreated Core C411are approximately 0.15 and 0.37 at the test termination, respec-tively. As mentioned before, the core is strongly oil-wetting andthe nC10 imbibition shows twice as much saturation as water. Acomparison of water and nC10 imbibition before and after thetreatment is shown in Fig. 3. Altering wettability from oil-wettingto preferentially gas-wetting reduces liquid imbibition. Water satu-ration decreases from 0.17 to 0.1, and nC10 imbibition decreasesfrom 0.36 to 0.21. Therefore, the treatment reduces liquid satura-tion by approximately 40% at termination.

The result of spontaneous imbibition of Core H122 with 2%11-12Pb treatment is shown in Fig. 4; 2% treatment results inapproximately 50% reduction of water saturation. Sw decreasesfrom 0.12 to 0.06. The 2% treatment with 11-12Pb is as effectiveas 4% treatment in the spontaneous imbibition of water.

Fig. 2—Contact angle before and after treatment; H122 before treatment (a); H122 after treatment (b); O319 before treatment (c);O319 after treatment (d); C422 before treatment (e); and C422 after treatment (f).


The treatment with 11-12Pa in Core O319 results in less im-bibition than that with 11-12Pb, as shown in Fig. 5. The watersaturation decreases from 0.37 to 0.04, and oil saturation decreasesfrom 0.47 to 0.24. The treatment reduces water imbibition by 90%and nC10 imbibition by 50% at 500 minutes. Because the watercontact angle in Core O319 changes significantly (from 20 to150°) from the treatment, compared to Cores C411 and H122, thereduction in water imbibition is also more pronounced.

Absolute Permeability. The absolute permeability is measuredusing nitrogen. Before the treatment, the permeability of CoresC411 and H122 is 1.37 and 27 md, respectively. After the treat-ment with 11-12Pb, the absolute permeabilities decrease to 0.65md for Core C411 and 21 md for Core H122. There is approxi-mately 50% reduction of permeability by 4% treatment and ap-proximately 22% reduction by 2% treatment. We have used adifferent batch 11-12Pa with various concentrations in variousother core samples and have not observed a considerable reductionin permeability. For example, the permeability of Core O319 staysthe same after the treatment. The pretreatment process solves theproblem of permeability reduction to a large degree (see Table 1).

Initial Liquid Saturation. We have examined the effect of initialliquid saturations on the treatment. Five treatments with different

initial liquid saturations have been performed using Berea cores.The experimental conditions are described in Table 3. For 8%11-12P treatment, 79% ethanol, 10% water, and 3% acetic acid areused. For the alcohol treatment (BrC), we use 87% ethanol. Aftereach treatment, we performed water- and nC10-imbibition tests.The results are shown in Figs. 6a and 6b, respectively.

The alcohol treatment without fluorochemical in Berea CoreBrC shows less water imbibition than the untreated imbibition test.Water saturation decreases by 18%, and nC10 saturation is approxi-mately the same. Compared to 11-12P treatment, however, alcoholtreatment (BrC) shows considerably more liquid imbibition. 8%treatment (LBm5) with 11-12Pa in dry core reduces water satura-tion by 95% and oil saturation by 80% at termination. For the testin Berea cores, treatment with 11-12P is more effective for waterimbibition than for nC10 imbibition. The treatment with L-19062in BrF shows slightly more water imbibition compared with thatwith 11-12P. However, the nC10 imbibition is almost the same asalcohol-treated Core BrC and untreated Core BrD. The imbibitionresults are consistent with contact-angle tests.

When the cores are initially saturated with liquid—either wateror nC10—the effect of treatment is still significant in imbibition.The treatment with liquid-saturated cores may be slightly less ef-fective than that in the dry cores, as shown in Fig. 6. However,these differences are small. The treatment effectiveness is, there-fore, independent of the initial-saturation state.

Flow TestThis section includes experimental results of two-phase-flow testsusing single-phase and two-phase injections. We inject the aque-ous phase in a gas-saturated core. Next, water and gas are injectedsimultaneously and flow rate and pressure drop are measured atsteady state. Two-phase relative permeabilities are calculated andcompared before and after the treatment. Single-phase nC10 injec-tion in a gas-saturated core is also tested at a high temperature.

Single-Phase Injection. The gas-saturated core, C411, is placed inan oven at 80°C with the overburden pressure of 1,000 psig. Anaqueous phase is injected at 1 cm3/min, and the pressure drop isrecorded with time. The results are shown in Fig. 7 for the un-treated and treated core. At steady state, at approximately 30 PV,the untreated core has 107 psi and the treated core has 69 psi ofpressure drop. As mentioned before, the absolute permeability de-creases from 1.37 to 0.65 md without pretreatment. Consideringthis reduction, the relative mobility of the aqueous phase increasessignificantly. The relative permeability of water at steady stateincreases from 0.39 to unity after the treatment. Note that becauseof permeability reduction, the core has become heterogeneous andthe reduction is mainly toward the inlet. As a result, the relativepermeabilities at steady state may not have physical meaning.

Fig. 4—Spontaneous water imbibition for Core H122 before andafter treatment.

Fig. 5—Spontaneous imbibition of water and nC10 for Core O319before and after treatment.

Fig. 3—Spontaneous imbibition of water and nC10 for Core C411before and after treatment.


The pressure-drop history is shown in Fig. 8 for 2% treatmentin Core H122. Because we perform this experiment with two dif-ferent injection rates, the data are presented in terms of the dimen-sionless pressure drop defined by pD=kA�p/qw�wL. The dimen-sionless pressure drop at 30 PV decreases from 4.9 for the un-treated core to 3.3 for the treated core at 2-cm3/min of waterinjection rate. At 4-cm3/min water-injection rate, the dimension-less pressure drop decreases from 4.7 to 3.0. Therefore, the waterrelative permeability at steady state increases from 0.2 to 0.31 for2-cm3/min of water injection rate and from 0.21 to 0.33 for 4-cm3/min water-injection rate. Water shows 60 to 70% of mobility in-crease after the treatment. Unlike the spontaneous imbibition re-

sults, the flow test shows that the 11-12Pb treatment with higherconcentration (4%) in Core C411 is more effective than 2% treat-ment in Core H122.

We also perform a series of water-injection tests in gas-saturated Berea cores at ambient conditions (20°C). As noted be-fore, these cores are treated at different initial liquid saturations(see Tables 1 and 3). Fig. 9 shows that all three treatments with11-12P behave similarly and dimensionless pressure drop stabi-lizes at approximately 1.2. The water relative permeabilities ofthree treated cores at steady state are approximately 0.83. Therelative permeability of water is 0.98 in Core BrF for the 12%L-19062 treatment at steady state. Dimensionless pressure drop forthe untreated core and the alcohol-treated core are 2.67 and 2.13,respectively. These values correspond to water relative permeabili-ties of 0.38 and 0.47, respectively, at steady state. Similar to thespontaneous-imbibition results in Fig. 6, the alcohol treatment in-creases water mobility but treatments with 11-12P and L-19062 atany initial liquid saturations improve the phase mobility beyondthe untreated core or the alcohol-treated core. In subsequent mea-surements, we find that the treatment with alcohol results in atemporary change of wettability.

Water and nC10 injection at 140°C were also performed in CoreO319. There was no permeability reduction from treatment. Waterand nC10 are injected at 0.2 cm3/min, and the pressure drop isrecorded with time. The results are shown in Fig. 10 before andafter the treatment. For aqueous-phase injection in Core O319, thepressure drop at 20 PV decreases from 44 psi (PD�2.76) to 21 psi(PD�1.38) at 0.2 cm3/min of water-injection rate. The water rela-tive permeability at steady state increases from 0.35 to 0.72. In thecase of nC10 injection, the untreated core has 40.4 psi (PD�2.57)of pressure drop and the treated core has 36.3 psi (PD�2.31) at 5.5PV. Therefore, the mobility of the oleic phase at steady stateincreases by 10%. The test shows that the selected chemical iseffective without the reduction of permeability. The relative mo-

Fig. 6—Water and nC10 imbibition with various initial satura-tions in Berea cores; water imbibition (a) and nC10 imbibi-tion (b).

Fig. 7—Pressure drop at water-injection rate of 1cm3/min in gas-saturated core: C411, 80°C.


bility of the aqueous phase doubles from the treatment. However,4% 11-12Pa treatment increases oleic-phase mobility by only 10%at steady state.

The treatment with 4% L-19062 improves water relative per-meability at steady state by 54 and 120% in Cores H113 and C422,respectively (see Fig. 11). Because the water relative permeabilityat steady state for untreated Core H113 is relatively high (0.53)compared with Core C422 (0.32), Core C422 has more room forimprovement. The single-phase water-injection test in Core O334shows more improvement compared with Cores H113 and C422.The water relative permeability at steady state for Untreated CoreO334 is 0.22, and it increases to 0.58 after treatment with 4%of L-19062.

From single-phase-injection tests, we find a considerable in-crease in liquid mobility even with the absolute permeability de-crease. The treatment with higher concentration provides fur-ther improvement.

Two-Phase Injection (Relative Permeability Measurement).Relative permeability measurement is performed in Berea CoresBrD, LBm5, and BrF. Core BrD is untreated, and Cores LBm5 andBrF are treated with 8% 11-12Pa and 12% L-19062, respectively(see Table 3). Fig. 12 presents the relative permeability measure-ments for treated and untreated cores. We use the constant pressuredrop of 30 psi throughout the experiments in Berea cores. The datafrom Tang and Firoozabadi (2002) are also plotted in Fig. 12. Thetreatment with 2% FC-722 shows only slight improvement com-pared to the untreated condition; treatments by 11-12Pa andL-19062 clearly show further improvement in Berea cores.

Fig. 13 shows relative permeability data in which constantpressure drops of 120 and 25 psi are used for Cores C411 andH122, respectively. Fig. 13 shows the increase of gas relativemobility when krw is large. When krw is small, it seems that the gasmobility decreases after the treatment. Note that the region withsmall krw represents large krg/krw (≈100 or larger) and relativelylow water saturation, in which the water-blocking problem maynot be significant. When the core is treated with the 2% 11-12Pb,there is no significant increase in gas relative permeability; on theother hand, there is a significant increase with the 4% treatment.

Fig. 14 shows relative permeability data of untreated core andtreated core with L-19062. Unlike the previous results, we observethat the gas relative permeability is improved throughout the wholerange of krw. Fig. 14 also shows that the treatment with higherconcentration improves mobility further.

We apply different pressure drops for relative permeabilitymeasurements in Cores H121 and H122, which are from the sameformation and close to each other. Whitson et al. (1999) showed

that the plot of krg vs. krg/kro shows a dependency on the capillarynumber and that gas relative permeability increases with capillarynumber. The experimental study by Tang and Firoozabadi (2001)suggested that the effect of pressure gradient is more significant inintermediate-wet state compared to strongly water-wet state. Fig.15 presents the gas and water relative permeabilities at three dif-ferent pressure drops. The relative permeabilities in Fig. 15 do notrepresent the same capillary number. Generally, a high pressuredrop is associated with high capillary number. For the untreatedcore, Fig. 15a shows that the relative permeability at the pressuredrops of 100 and 200 psi is the same. However, for the treated corein Fig. 15b, gas relative permeability increases with increase inpressure drop. This result is consistent with the studies of Whitsonet al. (1999) and Tang and Firoozabadi (2001).

We mentioned earlier that the spontaneous imbibition in somecores treated with 2% and 4% concentrations is the same. How-ever, flow tests show that the treatment with the higher concen-tration provides further improvement in relative permeability.

ConclusionsWe have altered the wettability of cores from two reservoirs, withpermeabilities in the range of 0.3 to 27 md, and Berea sandstonecores. For one of the reservoirs, water blocking around the well-bore is a major issue. In the other reservoir, hydrocarbon blockingis significant. Results presented in the paper show that for bothreservoir rocks, wettability alteration can be effective for reducingwater blocking. These conclusions are based on the treatment atreservoir temperature of 140°C, as well as flow testing at 140°C.From the experimental results of this work, the following conclu-sions can be drawn:1. The wettability of reservoir rock can be altered from oil-wetting

to preferentially gas-wetting by treatment with 11-12P andL-19062.

2. The spontaneous-imbibition tests show 40 to 90% reduction ofwater saturation for the reservoir rocks after the treatment. In-creasing surfactant concentration has negligible effect on waterimbibition for some concentration range.

3. In some cases, the treatment decreases absolute permeability.When there is permeability reduction, the problem can be over-come by using the pretreatment process.

4. The treatment is effective with or without initial liquid satura-tion (oil or water).

5. The single-phase water-injection tests in the gas-saturated coreshow considerable increase in water mobility. The treatmentwith higher concentration results in higher water mobility. Theeffect of the treatment is the same at various temperatures (20to 140°C).

Fig. 9—Dimensionless pressure drop with different treatmentconditions for water injection: Berea cores, 20°C.

Fig. 8—Dimensionless pressure drop for water injection at tworates: H122, 80°C.


6. The gas relative permeability may increase in a wide range fromthe treatment. The treatment with higher chemical concentrationmay be more effective in the concentration range we studied.

We also observe that there is an increase in mobility in the gas/oilsystem. However, the improved mobility is much less pronouncedthan the gas/water system. Our belief is that we have now devel-oped a process for water blocking for field testing in gas-condensate reservoirs.

NomenclatureA � areak � absolute permeabilityL � length

M � molecular weightp � pressureq � flow rateR � universal gas constantS � saturationT � temperature

W � mass rate

Z � gas deviation factor� � high-velocity coefficient� � viscosity� � phase

Subscript

D � dimensionless valueg � gaso � oilr � relative value

w � water

Acknowledgments

This work was supported by the member companies of the Res-ervoir Engineering Research Institute (RERI). Their support isappreciated. We also thank the 3M Corporation for providing thechemicals. The valuable suggestions by and discussion withManny Arco of 3M Corporation are highly appreciated.

Fig. 10—Dimensionless pressure drop for oil and water injec-tion at 0.2 cm3/min in gas-saturated core: O319, 140°C; waterinjection (a) and oil injection (b).

Fig. 11—Dimensionless pressure at water-injection rate of 1cm3/min (O334), 1 cm3/min (H113), and 0.5 cm3/min (C422) ingas-saturated cores: 140°C.

Fig. 12—Effect of treatment on relative permeability: Bereacores, 20°C.


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Fig. 13—Effect of treatment on relative permeability: C411 andH122, 80°C.

Fig. 15—Effect of pressure drop on relative permeability for un-treated and treated cores; untreated core is H121, 20°C (a) andtreated core is H122, 20°C (b).

Fig. 14—Effect of treatment on relative permeability: H131 andC422, 20°C.


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SI Metric Conversion Factors°API 141.5/(131.5+°API) � g/cm3

cp 1.0* E − 03 � Pa�s

dyne 1.0* E − 02 � mN

°F (°F − 32)/1.8 � °C

psi 6.894 757 E + 00 � kPa

*Conversion factor is exact.

Myeong Noh is a research engineer at Chevron Corporation inHouston. His research interests include multiphase flow in po-rous media, carbon dioxide sequestration, and enhanced oilrecovery for heavy-oil reservoirs. Noh holds a BS degree fromHanyang University, Seoul, South Korea, and MS and PhD de-grees from the University of Texas at Austin, all in petroleumengineering. Abbas Firoozabdi is senior scientist and director atthe Reservoir Engineering Research Institute (RERI) in Palo Alto,California and a professor of chemical engineering at YaleUniversity, New Haven, Connecticut. His main area of focus ishydrocarbon energy production and environmental steward-ship on the basis of thermodynamics and mathematical analy-sis. Firoozabadi holds a BS degree from the Abadan Institute ofTechnology, Abadan, Iran and MS and PhD degrees from theIllinois Institute of Technology, Chicago, all in gas engineering.He is the recipient of the 2002 SPE Anthony Lucas Gold Medal,and the 2004 SPE John Franklin Carll Award.


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