wettability alteration to intermediate gas-wetting in …wettability alteration, the liquid-phase...

Transport in Porous Media 52: 185–211, 2003.© 2003 Kluwer Academic Publishers. Printed in the Netherlands.

185

Wettability Alteration to Intermediate Gas-Wettingin Porous Media at Elevated Temperatures

GUO-QING TANG∗∗ and ABBAS FIROOZABADI∗Reservoir Engineering Research Institute, 385 Sherman Avenue, Palo Alto, CA 94306, U.S.A.

(Received: 27 September 2001; in final form: 21 June 2002)

Abstract. Wettability alteration to intermediate gas-wetting in porous media by treatment with FC-759, a fluorochemical polymer has been studied experimentally. Berea sandstone was used as themain rock sample in our work, and its wettability before and after chemical treatment was studiedat various temperatures from 25 to 93◦C. We also studied recovery performance for both gas/oil andoil/water systems for Berea sandstone before and after wettability alteration by chemical treatment.Our experiment shows that chemical treatment with FC-759 can result in: (1) wettability alterationfrom strong liquid-wetting to stable intermediate gas-wetting at room temperature and at elevatedtemperatures; (2) neutral wetting for gas, oil, and water phases in two-phase flow; (3) significantincrease in oil mobility for gas/oil system; and (4) improved recovery behavior for both gas/oiland oil/water systems. This work reveals a potential for field application for improved gas-welldeliverability and well injectivity by altering the rock wettability around wellbore in gas condensatereservoirs from strong liquid-wetting to intermediate gas-wetting.

Key words: intermediate gas-wetting, gas condensate reservoirs, fluorochemical polymer.

1. Introduction

Wettability alteration in water–oil systems in relation to oil recovery perform-ance has been studied extensively in the past several decades (Owens and Archer,1971; Morrow et al., 1973, 1986; Penny et al., 1983; Maini et al., 1986; Cuiec,1990; Kovseck et al., 1993; Legens et al., 1998; Fleury et al., 1999; Tang andFiroozabadi, 2001). However, wettability alteration in gas–liquid system (i.e. gas–oil and gas–water) through chemical treatment has been studied only recently. Liand Firoozabadi (2000) Tang and Firoozabadi (2002) investigated wettability alter-ation from strong liquid-wetting to intermediate gas-wetting, using fluorochemicalpolymers, FC-722 and FC-759. They showed that a stable intermediate gas-wettingcan be established in Berea sandstone and chalk at room temperature. Throughwettability alteration, the liquid-phase mobility for a gas–liquid system increasessignificantly, showing potential for improved gas-well deliverability in gas conden-state reservoirs. In Li and Firoozabadi (2000) and Tang and Firoozabadi (2002),the wettability alteration in intermediate gas-wetting has been studied at room

∗ Author for correspondence.∗∗ Present address: Stanford University, Stanford, CA, U.S.A.

186 GUO-QING TANG AND ABBAS FIROOZABADI

temperature. One major goal of this work is the study of the effect of wettabil-ity alteration at high temperatures encountered in gas reservoirs. In this work, wewill first present the experimental and the chemical treatment process followed byimbibition and coreflooding tests.

2. Experimental

2.1. FLUIDS AND ROCKS

Normal decane (n-C10) with specific gravity of 0.73 at T = 25◦C was used as theoil phase in most experiments. In some tests, we used normal tetradecane (n-C14).The measured viscosity of n-C10 was 0.92 cp at T = 25◦C and 0.51 cp at T = 90◦C.In our results, the term oil refers to n-C10 used in the tests. Distilled water dissolvedwith 0.2% NaCl (brine) was used as the water phase. The specific gravity of brinewas 1.012. The viscosity of brine was 1.012 cp at T = 25◦C and 0.54 cp at T = 90◦C.Air was used as the gas phase. Berea sandstone with air permeability of 320 md anda porosity of 20% was used in most experiments. Two dimensions of Berea wereused in this work. One had a length of about 5–6 cm and a diameter of 2.54 cm; thisgroup was used mainly for spontaneous imbibition tests. The other one had a lengthof 18 cm and a diameter of 2.54 cm; this group was used mainly for corefloodingtests. Kansas outcrop chalk with an air permeability of 1.3 md and a porosity of31% was used in some experiments for examining the results for a second rocktype. The length of chalk samples was about 6–7 cm and the diameter was 2.54 cm.Relevant data of the rock properties are listed in Table I.

2.2. CHEMICAL TREATMENT

FC-759 and FC-722 polymers manufactured by 3M Specialty Materials were usedto alter the wettability of Berea and chalk samples from strongly liquid-wetting tointermediate gas-wetting. These chemicals have specific functional groups whichserve different purposes. Among these chemicals, FC-759 was used for most of thisstudy because it was developed for coating on the surface of porous media (Linert,1997). Figure 1 shows the chemical structure of FC-759. The fluorochemical groupprovides water and oil repellency; the silanol and anionic groups chemically bondonto the rock surfaces providing a durable treatment; the anionic and nonionicgroups make the polymer hydrophilically soluble. In addition, some Berea sampleswere treated with 1% stearic acid solution. The sample was saturated and aged with1% stearic acid solution (1% stearic acid dissolved in normal decane) at room tem-perature for 10 days. The wettability of the rock treated with 1% stearic acid showsa very weak water-wetting for a water/oil system (Tang and Firoozabadi, 2001).

In previous work Tang and Firoozabadi (2002) reported two processes to alterrock wettability from strongly liquid-wetting to intermediate gas-wetting: process-1 and process-2. In this work, the core samples were treated using process-2.For this process, the core sample with about 10–15% initial water saturation was

WETTABILITY ALTERATION TO INTERMEDIATE GAS-WETTING IN POROUS MEDIA 187

Table I. Core properties and other relevant data

Core ka φ L d Tr Chemical Fluid

(md) (%) (cm) (cm) (◦C) treatment system

B1 316 20.1 5.8 2.5 25/93 – g/o

B2 308 20.0 5.7 2.5 25 – g/o

B3a 310 20.3 6.2 2.5 25 8% FC-759 g/o

B4b 301 20.5 5.9 2.5 25 8% FC-759 g/o

B5 321 20.3 6.1 2.5 25/90 – g/o

B6 311 20.1 5.7 2.5 25/55/88 2% FC-722 g/o

B7 323 20.5 6.2 2.5 25/50/70/93 10% FC-759 g/o

B8 317 20.1 5.9 2.5 25 8% FC-759 w/o

B9 296 19.9 6.2 2.5 25 10% FC-759 g/o

B10 322 22.4 18.0 2.5 25 8% FC-759 g/o

B11 318 22.2 18.2 2.5 25 – g/o, w/o

B13 308 22.0 17.8 2.5 25/90 10% FC-759 g/o

B14 321 21.9 18.1 2.5 25/90 – g/o

B15 310 21.8 18.4 2.5 90 10% FC-759 g/o

B16 293 20.1 6.2 2.5 25 10% FC-759 g/o

B17 289 20.0 5.8 2.5 25 10% FC-759 g/o

B18 303 20.1 6.0 2.5 25 10% FC-759 g/o

B19 327 20.5 5.6 2.5 25 10% FC-759 g/o

B20c 310 20.3 6.2 2.5 25 10% FC-759 g/o

B21c 289 20.0 5.7 2.5 25 10% FC-759 g/o

B22c 312 20.4 6.1 2.5 25 10% FC-759 g/o

B23 309 20.3 6.2 2.5 25 10% FC-759 g/o

B24 279 19.9 6.0 2.5 25 10% FC-759 g/o

B25d 311 20.1 6.3 2.5 93 10% FC-759 g/o

B26 301 20.0 6.0 2.5 93 10% FC-759 g/o

C2 1.31 31.2 6.7 2.2 25 8% FC-759 g/o, w/o

a Pretreated with stearic acid. b Pretreated with crude oil. c Cut cores. d n-C14 was oil phase.

Figure 1. Chemical structure of FC-759 (Linert, 1997).


first saturated with chemical solution using an evacuating system. Then, it wassubmerged in the same chemical solution; the container was sealed and aged atT = 90◦C for 3 days. After aging, the core sample was cooled to room temperatureand was displaced with dry air to remove all liquids. The core sample, either dry orwith some initial water saturation (re-established), was then used for imbibition orflooding tests. In process-2, unlike process-1, we do not heat the dry core at hightemperature for stabilizing the chemical adsorption (i.e. process-1).

2.3. IMBIBITION AND COREFLOODING PROCESS

The air-saturated core was hung under an electronic balance and placed in eitheroil or water to carry out spontaneous imbibition tests (see Figure 2(a)). For thetests conducted at room temperature, the core was hung on the balance all the timeand change in the weight of the core sample versus time was recorded; for the testconducted at elevated temperature, the core sample and the container were placedin an oven at the test temperature. The weight of the core sample was measuredusing the electronic balance versus time.

Coreflooding tests were carried out in the temperature range of about 25–90◦C.Figure 2(b) shows a schematic of the apparatus for coreflooding tests. The coresample was covered with FTP heat-shrinking tubing and placed in a visual core-holder. It was positioned horizontally to avoid gravity effect. A confining pressureof 300 psig was used. In some tests, gas was injected at constant inlet pressure;in others, oil (or water) was injected at constant rate. The produced gas and oil(or water) were separated in the separator installed at the outlet; the gas and oil(or water) production rates were measured versus time. The pressure-drop across

Figure 2a. Schematic of the apparatus for spontaneous imbibition tests.


Figure 2b. Schematic of apparatus for coreflooding tests.

the core was measured using a Validyne differential pressure transducer. For thetests performed at 90◦C, the injected liquids were heated in the pre-heater whichwas made of a 20 ft coiled copper tubing with an inside diameter of 1 mm beforeentering the core.

3. Results

3.1. WETTABILITY ALTERATION TO INTERMEDIATE GAS-WETTING

In this section, we present some aspects of wettability alteration from strong liquid-wetting to intermediate gas-wetting using the chemical treatment process that wasdescribed above. Gas recovery and oil imbibition rate by spontaneous oil imbib-ition are used to characterize the wettability state of the core before and afterchemical treatment.

3.1.1. Uniformity of Altered WettabilityFigure 3(a) shows the core samples (B20–B23) used to examine the uniformity ofthe altered wettability by chemical treatment. Four cylindrical cores were treatedwith 10% FC-759 at T = 93◦C. After chemical treatment, three of them were cutto make different shapes and fresh surfaces for oil imbibition. Core B23 was notcut; core B21 was cut from the middle along radius; core B22 was cut from themiddle along the axial direction; and core B21 was cut from the two ends (seeFigure 3(a)). These four cores were then used for spontaneous oil imbibition test-ing at room temperature. Figure 3(b) presents the relevant experimental data for


these four cores. Ta represents the aging temperature and Tt represents the testtemperature. To assess the change in wettability, imbibition data for the untreatedBerea sample (B1) is also presented as a reference. The results shown in Figure 3(b)reveal that both oil imbibition rate and final gas recovery are similar for the fourtreated cores. Increase in imbibition surface areas for cores B20–B22 does not raiseoil imbibition rate, indicating that the altered wettability by chemical treatment isuniform throughout the cores.

3.1.2. Effect of Initial Wettability StateBerea samples with three wettability states, strongly water-wet, weakly water-wet,and weakly oil-wet were treated with 8% FC-759 to examine the effect of initialwettability state on wettability alteration to intermediate gas-wetting by FC-759treatment. Untreated Berea sample (B2) was used as a reference for strongly water-wet sample. The measured Amott Index to water (Iw) for core B2 was 1.0. To alterthe wettability to a weakly water-wet core, Berea sample (B3) was pre-treated with1% stearic acid solution using the procedure described by Tang and Firoozabadi(2001). The measured Amott index (Amott, 1959) to water (Iw) was 0.18 for coreB3 after it was pre-treated with stearic acid solution. For the weakly oil-wet coresample, Berea sample (B4) was pre-treated with the crude oil from Kagel field, RioBlanco, Co. The dry core sample was saturated with crude oil and aged at T = 90◦Cfor 10 days. Thereafter, the core sample was flooded with hot normal decane untilthe effluent was colorless. Then, the core was heated for 8 h at T = 105◦C to stabil-ize the adsorption of polar oil components. The measured Amott index to water (Iw)was zero and to oil (Io) was about 0.1 for core B4 after being treated with the crudeoil. The core samples with different initial wettability states (strongly water-wet,

Figure 3a. Schematic of the cores after cutting.

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Figure 3b. Gas recovery by spontaneous oil imbibition for cores treated with 10% FC-759 before and after cut.


weakly water-wet and weakly oil-wet) were then treated with 8% FC-759 usingthe procedure described above. After the cores were treated with 8% FC-759, theywere used for spontaneous oil imbibition tests with zero initial water saturation atroom temperature.

Figure 4 presents the measured imbibition data for the three Berea samples(B2, B3, and B4). The final gas recovery by spontaneous oil imbibition was about8% for treated core B2 (initially water-wet), 10% for treated core B3 (initiallyweakly water-wet), and 15% for treated core B4 (initially weakly oil-wet). Thewettability alteration to intermediate gas-wetting using 8% FC-759 treatment wasmildly influenced by the initial wettability state of the cores. The trend of the datain Figure 4 suggests that adsorption of FC-759 is not much affected by other polaroil components adsorbed onto the rock surfaces. Clean rock provides the surfacesfor FC-759 treatment for the most pronounced wettability alteration. However,the presence of other polar species is not detrimental to wettability alteration tointermediate gas-wetting by FC-759 treatment.

3.1.3. Effect of Initial Liquid SaturationFigure 5(a) shows the gas recovery by spontaneous oil imbibition for the coretreated at various initial water saturations. The final gas recovery decreases withincrease in initial water saturation, indicating a positive effect of initial water sat-uration on chemical treatment with FC-759. For all the three cores, the final gasrecovery was less than 10%. A substantial decrease in imbibition rate and final gasrecovery are observed due to wettability alteration from strongly liquid-wetting tointermediate gas-wetting. These results are in agreement with our previous studyfor the treated cores at zero initial water saturation (Tang and Firoozabadi, 2002)and provide strong evidence that wettability alteration to intermediate gas-wettingcan be achieved for the cores with about 10–20% initial water saturation.

In the wellbore of gas condensate reservoirs, liquid-condensate dropout couldbe as high as 60% (Tweheyo et al., 1999). Therefore, investigation of the effect ofinitial oil saturation on wettability alteration by FC-759 is of interest. Berea sample(B17) initially saturated with about 10% oil was treated with 10% FC-759 usinga treatment procedure similar to the other tests. Thereafter, the core was dried andused for oil imbibition test. Figure 5(b) shows that gas recovery increased quicklyto about 5% at the beginning of the test. After that, the oil imbibed into the coregradually. The oil imbibition continued to the end of the test. The gas recovery byspontaneous oil imbibition at the end of the test was about 33%. Higher gas recov-ery might have been obtained if we had continued the test. Thus, one may implythat initial oil saturation could reduce the effectiveness of wettability alteration.

In gas condensate reservoirs there is generally some initial water saturation priorto liquid dropout. For field application, further study of the wettability alterationwith coexistence of both water and oil saturation is useful. Three cores (B16, B18,and B19) were used for this purpose. We fixed the initial water saturation at 10%and changed the initial oil saturation from zero to 40%. Then the chemical was

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Figure 4. Effect of initial wettability on wettability alteration by 8% FC-759.

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Figure 5a. Effect of initial water saturation on wettability alteration by 8% FC-759.

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Figure 5b. Effect of initial oil saturation on wettability alteration by 10% FC-759.

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Figure 5c. Effect of initial water and oil saturation on wettability alteration by 10% FC-759.


injected into the cores, and the cores were aged at 93◦C for three days. After thecores were dried, they were used for imbibition tests. Figure 5(c) shows the imbib-ition data for these three cores (B16, B18, and B19). The results reveal that the oilimbibition rate and final gas recovery increase with increase in initial oil saturationat a constant initial water saturation of 10%. Comparison of Figures 5(b) and (c)reveals that initial water saturation improves the wettability alteration by FC-759.

3.1.4. Effect of TemperatureTo study the effect of temperature, we performed spontaneous imbibition testsat temperatures ranging from 25 to 93◦C. The treated-core sample was placedin a container with a sealed cap and was filled with oil. The container was keptin an oven at test temperature, except for quick measurement of core weight.The imbibition in an untreated core (B5) was used to establish a reference forstudying the effect of temperature on imbibition behavior. For core B5, increasein temperature from 25 to 90◦C showed only a small increase in imbibition rate(Figure 6(a)). Figure 6(b) shows the data for B15, a Berea core treated with 1%stearic acid solution. The results show that the oil imbibition rate and the finalgas recovery were high – both at T = 25 and 90◦C. The results also show thatstearic acid, which can establish a weakly water-wetting on Berea sandstone for awater/oil system, cannot establish an intermediate gas-wetting in Berea sandstonefor a gas/oil system. Figure 6(c) shows the experimental data obtained for core B6when treated with 2% FC-722 twice, at T = 25, 55, 75, and 88◦C. Oil imbibitionrate and the final gas recovery increased systematically with increase in tempera-ture. The imbibition rate at T = 88◦C was very high; the final gas recovery was52%, showing a liquid-wet behavior. To examine desorption of the chemical fromthe rock surfaces due to increase in temperature, we dried and weighed core B6after the tests. The measured data showed that no desorption occurred because theweight of the core remained unchanged. Thereafter, we performed a spontaneousoil imbibition test with core B6 at T = 25◦C (defined as run-2 in Figure 6(c)). Thecore sample behaved as intermediate gas-wetting again. The final gas recovery forrun-2 was only 11%, which was nearly the same as that for run-1. This behaviorimplies that increase in temperature may increase surface energy which improvesoil imbibition. Figure 6(d) shows the data for core Berea B7 treated with 10% FC-759 twice, at T = 25, 55, 70, and 93◦C. The results show that oil imbibition rateand final gas recovery were less influenced with temperature in the 25–93◦C range.In fact, from T = 25 to 70◦C, the oil imbibition performance did not change appre-ciably. Even at 93◦C the oil imbibition rate was slow, and the final gas recovery wasabout 27%. FC-759 is more effective than FC-722 at high temperatures, indicatingthat chemical structure is a dominant factor for wettability stability.

3.1.5. Effect of OilWe compared the oil imbibition behavior in the treated Berea at T = 93◦C usingboth normal tetradecane (n-C14) and normal decane (n-C10). Figure 7 shows the

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Figure 6a. Effet of temperature on spontaneous oil imbibition for untreated Berea.

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Figure 6b. Effect of temperature on spontaneous oil imbibition in Berea treated with 1% stearic acid.

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Figure 6c. Effect of temperature on spontaneous oil imbibition for Berea samples treated with 2% FC-722.


Figure 6d. Effect of temperature on spontaneous oil imbibition in Berea sample treated with10% FC-759.

Figure 7. Spontaneous imbibition of n-C10 and n-C14 for Berea sample treated with 10%FC-759.

data for the treated and untreated cores. For the untreated core, the oil imbibitionrate was slower for n-C14; the final gas recovery was the same for n-C10 and n-C14.For the treated core, both oil imbibition rate and final gas recovery were lower forn-C14. This result implies that the treated core may behave somewhat differentlywith different oils. We have embarked on a set of experiments using condensateliquids in our tests to study fluid flow in treated cores. The results will be publishedin the near future.


3.2. WETTABILITY FEATURES OF THE TREATED CORES

BY FC-759 FOR WATER/OIL SYSTEM

For cores (B8 and C2) treated with 8% FC-759, we also studied wettability featuresfor the water/oil system. Figure 8(a) presents the experimental data for water re-covery by spontaneous oil imbibition in a 100% water saturated cores, B8 and C2.This figure shows that oil cannot imbibe into the water-saturated cores, revealingthat the cores B8 and C2 are not preferentially oil-wet. Next, we dried the coresamples and saturated them with oil. The oil-saturated cores were then placed inwater to perform spontaneous water imbibition testing. Figure 8(b) presents theoil recovery by spontaneous water imbibition in the oil-saturated cores B8 andC2. About 7% oil was recovered by spontaneous water imbibition from thesetwo cores, indicating that the cores B8 and C2 were not preferentially water-weteither.

The above results reveal that when the core samples (Berea and chalk) weretreated with FC-759, it behaved neutrally wet for a water–oil system: neither oilnor water preferentially wets the rock surfaces. The established neutral wettingon Berea sandstone and chalk is stable based on measurements from tests of longduration (we do not present the results here for the sake of brevity).

3.3. IMPLICATIONS OF WETTABILITY ALTERATION TO INTERMEDIATE

GAS-WETTING

In a recent work Tang and Firoozabadi (2002) showed that gas/liquid flow couldbe improved significantly through wettability alteration from strong liquid-wettingto intermediate gas-wetting at room temperature. In this work, we study further the

Figure 8a. Water recovery by spontaneous oil imbibition for the cores treated with 8%FC-759.


Figure 8b. Oil recovery by spontaneous water imbibition for the cores treated with 8%FC-759.

effect of wettability alteration to intermediate gas-wetting on (1) recovery effi-ciency for both gas/oil and water/oil systems, (2) gas and oil relative permeabilities,and (3) injectivity of water or oil. The recovery efficiency tests were performed atroom temperature only, whereas relative permeability measurements are conductedboth at room temperature and at high temperature.

Two Berea samples, B10 and B11, with a length of 18 cm and a diameter of2.54 cm were repeatedly used in the following tests. B12 was treated with 8%FC-759 twice and B11 was not treated. All the tests were performed with thecoreholder positioned horizontally. The cores were 100% saturated with one phaseand the second phase was injected to displace the resident phase.

3.3.1. Recovery for Gas/Oil System

The data of gas recovery by oil injection in the untreated (B11) and treated (B10)cores saturated with air are presented in Figure 9(a). Oil was injected at a constantrate of 3 cm3/min. The data show that for the treated core with FC-759, the gasrecovery at oil breakthrough increased from 60 to 80%; the final gas recoveryincreased from 80 to 90%. The corresponding pressure-drop data for the tests withcores B11 and B10 are presented in Figure 9(b). The maximum pressure-drop wasabout 17.5 psi for the untreated core (B11) and about 7.2 psi for the treated core(B10). After oil breakthrough, the pressure-drop gradually decreased and stabilizedat 7.6 psi for the untreated core (B11) and at 5.6 psi for the treated core (B10).Decrease in pressure-drop after wettability alteration indicates an increase in oilinjectivity in porous media.


Figure 9a. Effect of wettability alteration on gas recovery by oil injection.

Figure 9b. Effect of wettability alteration on pressure drop for oil injection in gas saturatedBerea.

3.3.2. Recovery for Oil/Water SystemFigure 10(a) shows the results for water injection in 100% oil-saturated cores. Thewater injection rate 4 cm3/min. For the treated core (B10), the oil recovery at waterbreakthrough was about 56% and the final recovery was about 72%; about 16% oilwas produced after water breakthrough, indicating that the invading phase (water)was not preferentially wetting the rock surface. For the untreated core (B11), theoil recovery at water breakthrough was about 53% and the final recovery wasabout 54%. The oil recovery after water breakthrough was negligible, indicatinga typical process of wetting phase (water) displacing a non-wetting phase (oil).This result is consistent with the results obtained by Tweheyo et al. (1999). The


Figure 10a. Effect of wettability alteration oil recovery by water injection.

Figure 10b. Effect of wettability alteration on pressure-drop for water injection in oil saturatedcores.

pressure-drop data presented in Figure 10(b) also indicate a decrease after wet-tability alteration. The maximum pressure-drop for the untreated core (B11) was6.5 psi, and it then stabilized at 5.6 psi after water breakthrough. For the treated core(B10), the maximum pressure-drop was 2.9 psi, and it then stabilized at 1.4 psi afterwater breakthrough. The pressure-drop decreased about 3.5 times after wettabilityalteration, indicating a significant increase of water injectivity in the oil saturatedcore. This result is in line with the work reported by Penny et al. (1983).

Figure 11(a) shows the experimental data for oil injection in water-saturatedcores. The oil injection rate was 4 cm3/min. For the untreated core (B11), waterrecovery at oil breakthrough was about 30%, and the final recovery was about


Figure 11a. Effect of wettability alteration oil water recovery by oil injection in wa-ter-saturated cores.

Figure 11b. Effect of wettability alteration on pressure-drop for oil injection in wa-ter-saturated cores.

50%. Nearly two-fifth of the recovered water was produced after oil breakthrough,indicating a non-wetting phase (oil) displacing a wetting phase (water). For thetreated core (B10), the water recovery at oil breakthrough was about 51% andthe final recovery was about 62%. This behavior also indicates that the oil phase(the invading phase) was not preferentially wetting the rock. The correspondingpressure-drop data for oil displacing water are presented in Figure 11(b). The maxi-mum pressure-drop for the untreated core was about 3.4 psi; it then stabilized at2 psi. For the treated core, the maximum pressure-drop was about 1.7 psi, and it


then stabilized at 0.8 psi. The oil injectivity in the water-saturated core increased 2times with the alteration of wettability.

The results above show that after wettability alteration from strong liquid-wetting to intermediate gas-wetting, gas recovery by oil injection, oil recoveryby water injection, and water recovery by oil injection improved significantly. Inaddition, oil injectivity in the gas-saturated core, oil injectivity in water-saturatedcore, and water injectivity in the oil-saturated core improved significantly. Allthese results imply that wettability alteration through FC-759 treatment can alsobe applied to oil reservoirs and aquifers for improving water and oil injectivity andproductivity in water–oil flow.

3.3.3. Reduction of Oil Saturation in Porous Media by Dry Gas InjectionIn some gas condensate reservoirs, liquid dropout accumulation near the wellborecan cause a sharp decline in gas production (Hinchman and Barree, 1985; El-Banbiand McCain, 2000). Removal of liquids from the wellbore has been a challenge. Inthis work, we study the effect of wettability alteration on oil removal from a coreby injecting dry gas. Two Berea samples, B13 (treated with 10% FC-759 twice)and B14 (untreated), were saturated with oil (n-C10). They were then subjectedto dry air injection at a constant pressure gradient of 0.056 psi/cm. Oil saturationwas measured by weighing the core; thus the measured oil saturation is an averagevalue. The tests were carried out at T = 25 and 90◦C.

Figrue 12(a) presents the average oil saturation (n-C10) versus time for thetreated and untreated cores at T = 25◦C. Oil saturation in both cores decreasedquickly from 100 to about 60% during the first 20 min. Then, oil saturation de-creased slowly. Oil saturation in the treated core (B13) remained lower than that

Figure 12a. Effect of wettability on reduction of oil saturation by dry gas injection at roomtemperature.


Figure 12b. Effect of wettability on reduction of oil saturation by dry gas injection at hightemperature.

in the untreated core (B14), showing higher oil mobility in the treated core. Atinjection time t = 200 min, oil saturation in the treated core (B13) was about 30%and in the untreated core (B14) about 41%. The final oil saturation in the treatedcore (B13) was 23% and in the untreated core (B14) 35%.

Results at T = 90◦C are presented in Figure 12(b). At t < 200 min, the oil sat-uration decreased with a trend similar to the test at T = 25◦C. Thereafter, the oilsaturation in both cores continued decreasing at a lower rate. Oil saturation in thetreated core (B13) was about 20% lower than that in the untreated core (B14). Att = 2400 min, the oil saturation in the treated core (B13) reached zero, and theoil saturation in the untreated core (B14) reached 17%. Comparing the resultsshown in Figures 12(a) and (b), one may assume that at high temperatures, oilsaturation could be decreased further. We assume that in addition to the wettabilityalteration, the phase-behavior effect also reduces oil saturation in porous media athigh temperatures.

3.3.4. Gas and Oil Relative PermeabilitiesFigure 13(a) shows the measured gas and oil relative permeabilities for the un-treated core (B14) and treated core (B15) at 90◦C. Initial water saturation was zero,and the oil phase was normal decane (n-C10). The results show that the wettabilityalteration from strong liquid-wetting to intermediate gas-wetting resulted in thefollowing: (1) the oil saturation at the point for kro = krg reduced from 0.55 to0.48 PV; (2) the cross point relative permeability increased from 0.04 to 0.1 PV;(3) gas relative permeability decreased, but oil relative permeability increased sig-nificantly; and (4) the residual oil saturation decreased from 0.48 to 0.1 PV. Theseresults are in line with those obtained at room temperature (Tang and Firoozabadi,

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Figure 13a. Gas and oil relative permeabilities for treated and untreated cores at T = 90◦C: n-C10.


Figure 13b. Gas and oil relative permeabilities for treated Berea at T = 90◦C for n-C10 andn-C14.

2002). Figure 13(b) shows the measured gas and oil relative permeabilities for thetreated core (B15) at 90◦C. Both n-C10 and n-C14 were used. The results show thatthe gas relative permeability decreased and oil relative permeability increased whenthe oil phase was changed from n-C10 to n-C14. This trend is in agreement with ourimbibition study shown in Figure 7. As stated earlier, we are currently working withcondensate liquids, and the results will be the subject of a forthcoming publication.

4. Discussions and Conclusions

In this work, we have demonstrated that the wettability of Berea and chalk canbe altered to intermediate gas-wetting, using FC-759 for a temperature range of25–93◦C with initial water and oil saturations. From wettability alteration to inter-mediate gas-wetting, the following are shown: (1) improved recovery performancefor both gas/oil and oil/water systems; (2) increased oil phase mobility and decreasein residual oil saturation for a gas/oil system; (3) reduced oil saturation in porousmedia through injecting dry gas at both room and elevated temperatures; and (4)increased oil or water injectivity in water/oil flow.

In addition, during the course of the experiments, we did not observe core dam-age due to treatment with FC-759. Visual examinations show that fine particlesof the Berea and chalk become more stable after treatment with FC-759. There-fore, sand production could also reduce by adsorption of FC-759 onto the rocksurfaces.

We are now searching for new chemicals that will be very effective for wet-tability alteration to intermediate gas-wetting. Also, we are focusing on tests atreservoir conditions including using reservoir gas condensate fluids. The resultswill be published in due course.


Acknowledgements

This work was supported by the US DOE grant DE-FG22-96BC14850 and themembers of the Reservoir Engineering Research Institute (RERI). Their support isappreciated. We thank Mr. R. Jahanian for his assistance in the experimental work.

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