ree180914 doi: 10.2118/180914-pa date: 12-april-16 stage: … pub/11spe_ree_2016.pdf ·...

Demulsifier in Injected Water forImproved Recovery of Crudes That

Form Water/Oil EmulsionsM. Sun, Reservoir Engineering Research Institute; K. Mogensen, Eni; M. Bennetzen, Maersk Oil; and

A. Firoozabadi, Reservoir Engineering Research Institute

Summary

Waterflooding for oil displacement becomes a challenge whenwater-in-oil (W/O) emulsion forms upon contact of injected waterwith oil in the porous media. We have recently reported very-highpressure drops and high pressure fluctuations for a number ofcrudes in waterflooding. In this work, we address the challenge byadding a small amount of a demulsifier in the injected water. Thestability of W/O emulsion is affected by many factors, includingoil chemistry, brine chemistry, and temperature. We find that theW/O emulsion formation may correlate closely to the low totalacid number (TAN). In this work, we report the effectiveness of ademulsifier in significant reduction of pressure drop and elimina-tion of pressure-drop fluctuations. The demulsifier can be dis-persed in brine or water, and can be carried by injection fluid asan additive for improved oil recovery. Both micromodel observa-tions and coreflooding results show that W/O-emulsion formationis avoided when 100 ppm demulsifier is injected in the carrierbrine. Results also show that there is an increase in oil recovery.

Introduction

W/O and oil-in-water (O/W) emulsions are often observed in oilproduction (Schramm 1992; Kokal 2005; Abdel-Raouf 2012),Such emulsions are generally undesirable because they can causehigh pumping costs; pipeline corrosion; increased residence timein separators and, hence, reduced throughput; special-handlingequipment; and catalyst poisoning in downstream processingfacilities (Schramm 1992; Mohammed et al. 1993a; Sanchez andZakin 1994; Khan 1996; Hemmingsen et al. 2005; Kokal 2005;Abdel-Raouf 2012). Formation of W/O emulsion is also a majorconcern when water is injected in some reservoirs (Rezaei andFiroozabadi 2014). Many crudes contain natural surface-activecomponents, such as asphaltenes, resins, fatty acids, porphyrins,and waxes (Kokal 2005; Abdel-Raouf 2012). Asphaltenes act asnatural emulsifiers, to which other components can associate, thusaffecting emulsion stability (Mohammed et al. 1993b; McLeanand Kilpatrick 1997a; Wang and Alvarado 2009; Abdel-Raouf2012). On the other hand, resins solubilize asphaltenes in oil andremove them from W/O interface, therefore lowering emulsionstability (McLean and Kilpatrick 1997b). Waxes coadsorb at theinterface with asphaltenes and enhance the stability (Abdel-Raouf2012). Fatty acids (e.g., naphthenic) affect the emulsion stabilityat different pH values (Alvarado et al. 2011). Hemmingsen et al.(2006) have shown that the removal of the acidic compoundsfrom a North Sea oil stabilizes the W/O emulsions. Fine solid par-ticles, such as clay, sand, and mineral scales, can also coadsorbonto the interface and stabilize the emulsions (Kokal 2005;Abdel-Raouf 2012). The stability of the emulsion depends ontemperature and brine composition (Hemmingsen et al. 2005;Kokal 2005; Abdel-Raouf 2012).

In a recent work, we presented a systematic investigation onmacro- and microscale waterflooding performances of unusualcrudes that form tight W/O emulsions (stable after 15 months)

upon mixing with water and different brines (Rezaei and Firooza-badi 2014). The crudes are from a large oil field with stock-tank-oil viscosities in the range of 20–100 cp. We have reported forma-tion of tight W/O emulsions in situ by waterflooding. As a result,we have observed very-high pressure drops in porous media, apronounced pressure spike at the start of injection, and high pres-sure fluctuations. All these unusual phenomena raise serious chal-lenges to oil recovery from water injection.

Emulsions can be destabilized by thermal, mechanical, electri-cal, and chemical methods. Demulsifiers (or emulsion breakers)are commonly used for demulsification in the petroleum-produc-tion industry (Sun et al. 2002). The demulsifiers are usuallyethoxylated (or propoxylated) to alter their solubility in crudes.The addition of ethylene oxide increases water solubility; theaddition of propylene oxide does the opposite. For displacementof oil by water, the demulsifier should be dispersed in brine (car-rier fluid) to effective demulsification concentration. This featureis different from demulsifiers that are used in oil surface facilities;dissolution in oil serves the purpose. We have found a demulsifierthat has desired solubility in injected water or brine and is effec-tive in preventing in-situ W/O emulsion formation in water dis-placement of oil. Tests are conducted in both a glass microfluidicdevice with microscope observation and in a displacement rocksetup. The effects of demulsifier dosage on injection pressure andoil recovery are investigated, as well as the effect of injection rateand initial water saturation. In this work, we also provide an ex-planation for tight W/O emulsion formation, and discuss themechanism of improved oil recovery by the demulsifier.

Experimental

Materials. Three different brines are used in this work, with thecompositions presented in Table 1. Brines N and SW (seawater)are used as injection fluids, and FW Brine (formation-water brine)is used to establish the initial water saturation in the cores. Twocrudes are used in this study. At room temperature, Oil-1 has adensity of 0.89 g/cm3 and a viscosity of 25.6 cp and Oil-2 has adensity of 0.87 g/cm3 and a viscosity of 19.6 cp. The commercialdemulsifier (DEM) used in this investigation is an ethoxylatedresin, which is nonionic, provided by CECA, France. Other chem-icals used in this study include toluene (BDH, 99.5%), methanol(Cole-Parmer, 98.8%), isopropyl alcohol (IPA) (Cole-Parmer,99.5%), methylene chloride (Fisher Scientific, 99.9%), and chro-mic acid (Ricca Chemical, 10% wt/vol); these chemicals are usedfor cleaning the glass microfluidic device (micromodel).

We determine the TAN, which is a measure of crude acidity.The determination is based on the amount of potassium hydroxide(KOH) in milligrams needed to neutralize the acids (usually naph-thenic acids) in 1 g of oil. The total base number (TBN) is a mea-sure of alkalinity. It is measured in milligrams of KOH per gramof oil. In this study, the TAN/TBN value is measured by a916 TiTouch Potentiometric Titrator coupled with Solvotrode(from Metrohm).

Water-injection tests are conducted in a glass micromodel andin Berea cores. The relevant data of Berea cores (unfired or fired)are presented in Table 2. L and D are the length and diameter ofthe cores, respectively; pore volume (PV) and / are the totaleffective PV and the porosity of the cores, respectively; k is the

Copyright VC 2016 Society of Petroleum Engineers

Original SPE manuscript received for review 1 March 2015. Revised manuscript received forreview 25 January 2016. Paper (SPE 180914) peer approved 5 February 2016.

REE180914 DOI: 10.2118/180914-PA Date: 12-April-16 Stage: Page: 1 Total Pages: 9

ID: jaganm Time: 16:01 I Path: S:/REE#/Vol00000/160024/Comp/APPFile/SA-REE#160024

2016 SPE Reservoir Evaluation & Engineering 1

initial absolute permeability to either crude (in tests with the ini-tial oil saturation) or Brine FW (in tests with the initial water satu-ration); and Tf is the firing temperature. In the firing process, thetemperature of the oven is gradually increased over approximately5 hours to avoid thermal shock to the core, as suggested by Wuand Firoozabadi (2011). An increase in porosity and permeabilityis observed in firing, as expected. In the fired cores, there aresmaller variations in permeability from repeated use in compari-son with cleaning of the same core for repeated use.

Apparatus. The glass micromodel and coreflooding setup aredescribed in Rezaei and Firoozabadi (2014). A tensiometer (K12,by Kruss) is used to measure surface tension and interfacial ten-sion (IFT) of DEM solutions at steady state, and the critical mi-celle concentration (CMC). High-pressure Isco pumps are used inthe injection tests.

Procedures. Oil-1 is mixed with Brine N at different DEM con-centrations in volume ratio of 1:1 oil/water in a vial. The phaseseparation of mixtures is visually examined after shaking the vialsfor 1 minute. Fast separation indicates effective DEM concentra-tion. We follow the same procedures of core preparation, porositymeasurement, initial water saturation, waterflooding, and micro-model cleaning as described in our previous work (Rezaei andFiroozabadi 2014). In visual tests, the glass micromodel is satu-rated with Oil-1 at 50 psig overnight before injection of Brine Nand 100 ppm DEM brine solution. Ten coreflooding tests havebeen performed. Eight tests are performed at room temperature;two tests are performed at 56 �C (reservoir temperature). In thefirst three tests, the cores are saturated with Oil-1 and aged at 300psig for 7 days before waterflooding. In Tests 4, 5 and 6, Oil-2 isused to saturate the cores. In establishing the initial water satura-tion in Tests 7 and 8, the cores are initially saturated with BrineFW and aged at 200 psig for 3 days. The Brine FW is then dis-placed by Oil-2, which is then aged at 300 psig for 12 days beforewaterflooding by Brine SW. The final two tests (Tests 9 and 10)are similar to Tests 7 and 8, but at higher temperature.

Results and Discussion

Phase Separation in Vials. In a recent work (Rezaei and Firoo-zabadi 2014), we have systematically studied the formation of

tight W/O emulsions by mixing the unusual crudes with brines invials. In some crude samples, the emulsions are stable up to 15months at room temperature. In some other samples, emulsionsare stable for more than 3 days at 50 �C. In this work, we use thevial test method to screen different demulsifiers. The advantagesof vial tests (bottle test) include small quantity of samples, directvisual comparison, and simplicity. A demulsifier is consideredeffective if crude and brine separate quickly in the vial after thor-ough mixing. We tested a number of demulsifiers and found oneeffective at low concentration; it was then selected for furthertests in this work. We call this effective chemical DEM in thiswork. Fig. 1 presents the phase separation at different times infive vials that contain the DEM from 50 to 1,000 ppm (weight inbrine). A low concentration of DEM, as low as 50 ppm, is effec-tive. Water separates from crude completely in all five vials after10 minutes. There is more crude on the glass wall in the vial with50 ppm than in the other four vials. Without DEM, the Brine Nand Oil-1 form stable W/O emulsions even after 1 month.

Another important requirement is the solubility of demulsifierin brine (injection fluid). The low solubility of some demulsifiersprecludes their use in water injection. For instance, dodecylbenze-nesulfonic acid (DBSA) precipitates in brine at very low concen-tration although it may prevent W/O emulsions at concentrationsabove 1,000 ppm. It may also invert W/O emulsion to O/W emul-sion. DEM is not molecularly soluble in brine, but it can be dis-persed with no noticeable change to viscosity of brine. At roomtemperature, there is no precipitation of DEM up to 250 ppm inBrine SW and Brine N, and up to 100 ppm in deionized (DI)water in 24 hours. We have also performed vial testing at highertemperatures (50 and 70 �C), as presented in Fig. 2. Similar effec-tiveness is observed although the phase separation is faster athigher temperature.

The surface tension of DEM solutions at different concentra-tions in DI water and Brine N is measured to obtain the CMC, asshown in Fig. 3a. The CMC is 10 ppm. The fact that the surfacetension for both water and brine is very close relates to the non-ionic nature of the surfactant. The IFT of the crude and brine atdifferent DEM concentrations is also measured. The results arepresented in Fig. 3b. The IFT drops from 22 to approximately 10mN/m when the concentration reaches 25 ppm or higher. There isno significant effect when the concentration is higher than25 ppm. We have measured both surface tension and IFT three

Salt Concentration (mg/L) in Brine

Brine NaCl KCl CaCl2 MgCl2

N 40 000

SW 28 390 3051 7000 3510

FW 88 720 9534 21 877 10 969

Table 1—Brine composition.

Core L (cm) d (cm) PV (cm3) φ (% PV) k (md) Tf (°C)

B11N 14.6 3.8 34.0 20.5 22

B12N 14.6 3.8 34.5 20.8 28

B13N 14.6 3.8 34.2 20.7 11

B15F 14.6 3.8 36.2 21.7 77 850

B16F 14.6 3.8 36.1 21.7 77 850

B17F 14.6 3.8 35.9 21.6 105 850

B18F 14.6 3.8 35.6 21.5 57 850

B19F 14.6 3.8 35.7 21.6 102 850

B20F 14.6 3.8 36.2 21.7 106 850

B21F 14.6 3.8 35.9 21.6 102 850

Table 2—Parameters of Berea cores.



2 2016 SPE Reservoir Evaluation & Engineering

times at each concentration. The variations are less than 0.4%—smaller than data-point symbols in Fig. 3. In glass-micromodeltests, we compare results from Brine N injection and from100 ppm DEM in brine N. In coreflooding tests, we investigatethe effect of DEM concentrations: 0, 100, and 250 ppm.

The W/O emulsion formation of Oil-2 and brine is also inves-tigated. Fig. 4 presents phase separation in vials that contain Oil-2and brine SW (4.2 wt% salinity) and brine FW (13.1 wt% salinity)

of 1:1 volume ratio. Oil-2 has lower tendency to form W/O emul-sion than Oil-1. Small amount of Brine SW separates from crudeafter 3 hours. Different from Brine SW, high-salinity brine (BrineFW) does not form W/O emulsion with Oil-2. Brine FW separatesfrom Oil-2 completely after 3 hours. Oil-2 does not form tightW/O emulsions if the salinity of brine is higher than 8 wt%. Fromthe injection-pressure profile, we do not observe any indication ofW/O-emulsion formation in the cores after saturating them with

50 100 250 500 1,000 50 100 250 500 1,000

50 100 250

1 minute after shaking 2 minutes after shaking

10 minutes after shaking 30 minutes after shaking

500 1,000 50 100 250 500 1,000

Fig. 1—Phase separation in vials containing Oil-1 and Brine N of 1:1 volume ratio. The DEM concentrations in the five vials are 50,100, 250, 500, and 1,000 ppm from left to right.

20°C

1 minute

0 50 ppm 100 ppm 0 50 ppm 100 ppm 0 50 ppm 100 ppm

0 50 ppm 100 ppm 0 50 ppm 100 ppm 0 50 ppm 100 ppm

30 minutes

50°C 70°C

Fig. 2—Phase separation in vials containing Oil-1 and Brine N of 1:1 volume ratio at 20, 50, and 70 8C; 1 minute and 30 minutes aftershaking. The DEM concentrations in the three vials are 0, 50, and 100 ppm from left to right.




Brine FW and displacing the brine with Oil-2; there are no pres-sure fluctuations. Similar observations have been made in otherbrine/crude systems (Sohrabi and Mahzari 2014).

TAN/TBN Measurements and W/O-Emulsion Stability. TANis a measure of concentration of acidic compounds in crudes.TANs of Oil-1 and Oil-2 are 0.08 6 0.01 and 0.0165 6 0.0001,respectively; both are very low. TBNs are 1.50 6 0.10 and1.00 6 0.07. The standard deviations are based on at least threemeasurements. Low TAN oils can form stable W/O emulsions.Hemmingsen et al. (2006) have found that the W/O-emulsion sta-bility increases significantly by removing acidic compounds froma North Sea crude with initial TAN¼ 2.9 (Hemmingsen et al.2006). They explain the effect by the following mechanism.Naphthenic acids have similar ring structures as asphaltenes.They interact with asphaltenes and solubilize them in the bulkcrude (Auflem et al. 2002; Ostlund et al. 2003). Without thesecompounds, the solubility of asphaltenes decreases in the crude,promoting more-stable asphaltene aggregates at the W/O inter-face. These aggregates form stable films around water dropletsand prevent them from coalescence, as shown in Fig. 5a. Aneffective demulsifier accumulates at the W/O interface and repla-ces the asphaltenes, which leads to a reduction in emulsion stabil-ity. It may also increase the solubility of asphaltenes in the bulkcrude. The mechanism is illustrated in Fig. 5b. We have studiedemulsion formation in eight crudes. We observe a correlationbetween TAN and emulsion formation. The work will be submit-ted for publication later. We also like to point out that the DEMmainly accumulates at the fluid/fluid rather than at the fluid/rockinterface. In simple coreflooding tests, we find no measurableadsorption at the rock surface.

030

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60 80 100

DI water

Brine N

5

10

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25

0 50 100 150 200 250

Fig. 3—(a) Surface tension of DEM solutions in DI water and Brine N, (b) IFT between Oil-2 and Brine N vs. DEM concentration.

After shaking 30 minutes after shaking 1 hour after shaking 3 hours after shaking

Fig. 4—Phase separation in vials containing Oil-2 and Brine SW (left, 4.2 wt% salinity) and Brine FW (right, 13.1 wt% salinity) of 1:1volume ratio.

Flooding

Flooding

(a)

Asphaltene aggregate

Asphaltene monomerFunctional group

DEM moleculeLocal asphaltene molecules

are stabilized by DEM(b)

Fig. 5—Schematic of waterflooding in porous media (a) withoutDEM, W/O emulsions are formed; (b) with DEM, W/O emulsionsare not formed.




Water Injection in Micromodel. The glass micromodel is a 2Dporous medium, which allows visual observation of fluid flowingthrough pores and pore throats. In this study, we perform waterinjection in a micromodel saturated with Oil-1. We remove all thegas bubbles before water injection. The injection rate is0.005 cm3/min, and injection pressure is 2–3 psig.

Fig. 6 shows three microscopic images taken during injectionof brine N. In all images, W/O emulsions are observed. In the firstimage, the distorted emulsions do not coalesce into larger ones,indicating that there is very stable W/O interface and the emul-sions are tight. The second image demonstrates that the brine maynot flow through the necks. The red circles in the third imageillustrate interception and straining, two mechanisms of poreblockage by emulsions (Soo and Radke 1984; McDowell-Boyeret al. 1986). Interception is the adhesion of emulsion droplets onthe porous-medium inner wall, which narrows the flow pathway.Straining is the blockage of pore throat by emulsion droplets withlarger size. Because the micromodel is saturated with crude andaged overnight before waterflooding, the inner surface turnsto oil-wet, which promotes the generation of these droplets. SuchW/O emulsions form in-situ by snap-off at throats pushing drop-

lets into the pore bodies, which is a drainage event caused by theoil-wetness of medium.

When we add 100 ppm DEM in Brine N and perform injectionin the oil-saturated micromodel, the injection pressure drops toless than1 psig, significantly lower than with water injection byBrine N. Figs. 7a through 7c show the invasion of aqueous phaseinto the oil phase; panel (d) is a magnified image of the invadedarea. In these images, W/O emulsions are not observed. Brinetravels through the pores freely to displace the crude;“interception” and “straining” are absent. The accumulation ofDEM at the fluid/fluid interface increases elasticity of the inter-face on the basis of our measurements of interface viscoelasticity.To further investigate the effectiveness of DEM for oil recoveryof the unusual crudes by water injection, we perform coreflood-ing tests.

Waterflooding in Cores. Berea cores (Table 2) are used in thewaterflooding tests. A new clean core is used for each test. Wehave performed 10 tests, as presented in Table 3. Similar towater-injection tests in the micromodel, the experiments are per-formed at constant injection rate. In some tests, injection rate is

Fig. 6—Microscope images taken during waterflooding with Brine N.

(a) (b) (c) (d)

Fig. 7—Microscope images taken during waterflooding with 100 ppm DEM in Brine N. (a) through (c) show the sequence of inva-sion, and (d) is a magnified image of invaded area.

Test Crude Core DEM (ppm) Injection Rate (PV/D) Swi (HC PV) RFBKT (% HC PV) FRf (% HC PV)

1 Oil–1 B11N 0 5 0 31 48.0

2 Oil–1 B12N 100 5 0 34 53.6

3 Oil–1 B13N 250 5 0 35 63.5a

4 Oil–2 B15F 0 5 0 32 52.4a

5 Oil–2 B16F 100 5 0 32 63.7a

6 Oil–2 B19F 100 1 0 32 57.4a

7 Oil–2 B17F 0 5 0.287 38 55.5a

8 Oil–2 B18F 100 5 0.281 43 59.8a

9b Oil–2 B20F 0 5 0.246 40 56.3a

10b Oil–2 B21F 100 5 0.252 46 61.6a

HC = hydrocarbon. a. Final recovery after injection-rate increases at late times. b. Performed at 56°C.

Table 3—Summary of coreflooding experiments.




increased at late times to examine wetting state and possibly thecapillary end effect. We investigate the effects of DEM on injec-tion pressure and oil recovery. In the first three tests, the cores aresaturated with Oil-1 and aged at 300 psig for 7 days before water-flooding. Tests 4 through 6 are similar to Tests 1 through 3 exceptthat Oil-2 is used instead of Oil-1 and there is a longer aging timeof 15 days. In Tests 7 through 10 (Tests 7 and 8 at room tempera-ture; Tests 9 and 10 at reservoir temperature), the cores are ini-tially saturated with Brine FW at 200 psig and aged for 3 days.The Brine FW is then displaced by Oil-2, which is then aged at300 psig for 12 days before waterflooding. Swi is the volume frac-tion of the initial brine (initial water saturation) in the cores aftercrude displacement. RFBKT is the recovery at water breakthrough.FRf is the final recovery. The recovery is based on volume of ini-tial oil in the core.

Oil-Saturated Cores. The injection pressure profile and recov-ery of Tests 1 and 2 are presented in Fig. 8. The permeability ofTest 1 is 22 md and of Test 2 is 28 md. The injection pressure isvery different in these two tests despite the fact that the injectionrate is the same. When Brine N is injected into the oil-saturatedcore (Test 1), pressure spikes to 310 psi quickly before droppingto 50 psi. Afterward, the pressure increases again and fluctuates.Because of the limitation of the pressure transducer used in thesetup, pressures above 200 psig are not recorded. The early high-pressure data are read manually. The pressure spike and fluctua-tions indicate in-situ W/O-emulsion formation, observed in themicromodel tests in this work as well as in our previous study(Rezaei and Firoozabadi 2014). Water breakthrough occurs at0.31 PV injection. After 3.1 PV injection, pressure drops to a lowvalue and stays low. There is no further crude production. At thisstage, the water pathway has been fully developed. When100 ppm DEM is used (Test 2), the injection pressure is reduced

significantly. Water breakthrough occurs at 0.34 PV, later than inTest 1. The injection pressure is less than 40 psig throughout theexperiment. At the early stage, there are relatively few small pres-sure spikes; this could be caused by W/O-emulsion formation andquick breakup. Such small spikes are not observed at lower injec-tion rate (Test 6). The use of the 100 ppm DEM increases the finalrecovery to 53.6%, which is 12% higher than in Test 1(FRf¼ 48.0%). No water is found in the produced oil, on the basisof centrifugation at 5,000 rev/min for 30 minutes and microscopicobservations. Low injection pressure and absence of pressurefluctuations demonstrate the effectiveness of DEM in preventingW/O-emulsion formation in waterflooding.

In Test 3, a higher dosage (250 ppm) of DEM is used. Thecomparison between Tests 2 and 3 can be seen in Fig. 9. The corein Test 3 has a permeability of 11 md, much lower than 28 md inTest 2. Considering the permeability difference, the injectionpressure profiles at 5 PV/D are almost identical except that thereare fewer pressure spikes at early stage in Test 3. The recoveriesare also similar. The results are consistent with the vial tests andIFT measurements. A low DEM dosage of 100 ppm in the aque-ous phase is effective; it prevents formation of W/O emulsions.Higher dosage does not provide additional benefits. In Test 3,from 2.5 PV injection, the injection rate is increased to 15 PV/Dand again increased to 45 PV/D from 4 PV injection. The injec-tion pressure increases from the injection rate increase. The recov-ery also increases from 53.5 to 57.5%, then to 63.5% in the twosteps. When there is no further oil production, the injection pres-sure decreases, as expected.

In Tests 4 and 5, Oil-2 is used instead of Oil-1. The coreflood-ing-test results are similar to Tests 1 and 2, as presented inFig. 10. The permeability of the two Berea cores is the same, 77md. With 100 ppm DEM, the injection pressure is reduced

300Brine N

100 ppm DEM in brine N

Brine N

100 ppm DEM

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00 1 2 3

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Cru

de R

ecov

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(psi

g)

4 5

Fig. 8—Injection pressure profiles and crude recovery in Tests 1 and 2. Black represents the results of Test 1 (waterflooding withBrine N, 22-md core); red represents the results of Test 2 (waterflooding with 100 ppm DEM in Brine N, 28-md core). Injectionrate 5 5 PV/D.

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From 5 to 15 PV/d

From 5 to 15 PV/dFrom 15 to 45 PV/d

From 15 to 45 PV/d

250 ppm

100 ppm

250 ppm

100 ppm

Fig. 9—Injection pressure profiles and crude recovery in Tests 2 and 3. Red represents the results of Test 2 (waterflooding with100 ppm DEM in Brine N, 28-md core); blue represents the results of Test 3 (waterflooding with 250 ppm DEM in Brine N, 11-mdcore). Injection rate 5 5 PV/D. At late stage of Test 3, the injection rate is increased to 15 PV/D, then to 45 PV/D.




significantly with significantly fewer fluctuations. The final recov-ery also increases from 52.4 to 63.7%.

The effect of injection rate from the start of injection is inves-tigated in Test 6 (1 PV/D). We compare the results from Test 5 (5PV/D) and Test 6 (1 PV/D) in Fig. 11. Injection pressure in Test 6is proportional to the injection rate at early stage. The lower injec-tion rate in Test 6 gives somewhat lower recovery than in Test 5.We next increase the injection rate from 1 to 3 PV/D from 2 PVinjection, then increase it again to 9 PV/D from 4 PV injection, to27 PV/D from 5.5 PV and to 45 PV/D from 6.5 PV. The changesof injection pressure and recovery are similar to those to Test 3.The recovery in Test 6 increases from 39.5 to 51.3%, then to 55.5,56.9, and 57.4% from rate increases. The results from Tests 2, 3,5, and 6 demonstrate higher recovery with DEM in waterflooding.It is noticed that the final injection pressure in Test 6 is only one-third that of Test 5 although the final injection rate is 45 PV/D.This is probably caused by the different flooding history of cores.

Cores With Initial-Brine Saturation. Tests 7 and 8 are per-formed with the initial brine (Brine FW) saturation. We find thatwater breakthrough occurs later than in oil-saturated cores (Tests1 to 6). There is a clear difference between the cores with andwithout initial brine saturation. As expected, when the core isfully oil-saturated and aged, the rock surface becomes more oil-wet. However, if the core is initially brine-saturated, the rock sur-face may remain water-wet even after the brine is partially dis-placed by crude.

Fig. 12 depicts results from Tests 7 and 8 (initial saturationwith high-salinity brine) by water injection without DEM andwith 100 ppm DEM in the injection water. The water-break-through time is longer in the tests with the initial water saturations(see Table 3). The core in Test 8 has a permeability of 57 md,

lower than the 105 md in Test 7. However, the injection pressurein Test 7 is mostly higher at the injection rate of 5 PV/D. There issignificant spike in initial pressure in Test 7 compared with thelow spike in Test 8. Furthermore, there are no pressure fluctua-tions in Test 8, unlike Test 7. The incremental recovery afterbreakthrough is small in Tests 7 and 8. In both tests, the injectionrate is increased after 4.4 PV injections, and the incremental re-covery is less than 1% afterward. This is different from Tests 3, 4,and 6, in which much greater incremental recovery is obtained byincreasing injection rate at late stage. The late breakthrough andespecially the small incremental recovery after injection rateincrease indicate that the cores are more water-wet in Tests 7 and8. Note that the recovery in the test with 100 ppm DEM is higherthan that for the test without DEM (59.8% vs. 55.5%).

Tests 9 and 10 are performed at the reservoir temperature(56 �C). The results are similar to Tests 7 and 8, as presented inFig. 13. High injection pressure and fluctuations still exist if noDEM is used (Test 9). The effectiveness of DEM is demonstratedat higher temperature in Test 10. RFBKT and FRf are slightlyhigher in Tests 9 and 10 than in Tests 7 and 8, respectively.

Conclusions

We have found an effective demulsifier (DEM) that preventsemulsion formation in crudes that form W/O emulsion. Vial test-ing was used to screen different demulsifiers to find the effectiveadditive. The effectiveness is then demonstrated by water injec-tion in both micromodel and Berea cores. A very low dosage(100 ppm) of the selected demulsifier prevents the formation ofW/O emulsions, leading to significant reduction of injection pres-sure and elimination of high pressure fluctuations. The addition of

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From 5 to 15 PV/d

Brine

100 ppm DEM

Brine

100 ppm DEM

Fig. 10—Injection pressure profiles and crude recovery in Tests 4 and 5. Black represents the results of Test 4 (Brine SW, 77-mdcore); red represents the results of Test 5 (100 ppm DEM in Brine SW, 77-md core). Injection rate 5 5 PV/D. At late stage, the injec-tion rate is increased to 15 PV/D, then to 45 PV/D (in Test 5).

0.7

0.6

0.5

0.4

0.3

0.2

0.1

00 1 2


3 4 5 6 700

50

100

150

200

5 PV/d

1 PV/d

From 15 to 45 PV/d



From 27 to 45 PV/d

From 9 to 27 PV/d

From 3 to 9 PV/d

From 3 to 9 PV/d

From 3 to 9 PV/d

From 1 to 3 PV/d

From 1 to 3 PV/d

5 PV/d

1 PV/d

250

1 2


Inje

ctio

n P

ress

ure

(psi

g)

Cru

de R

ecov

ery

3 4 5 6 7

Fig. 11—Injection pressure profiles and crude recovery in Tests 5 and 6. Red represents the results of Test 5 (100 ppm DEM at 5PV/d, 77-md core); purple represents the results of Test 6 (100 ppm DEM at 1 PV/D, 102-md core). At late stage of Test 5, the injec-tion rate is increased to 15 PV/D, then to 45 PV/D. At late stage of Test 6, the injection rate is increased to 3 PV/D, then to 9, 27, and45 PV/D.




demulsifier also increases the oil recovery by reducing residualoil. The oil recovery is improved in waterflooding tests in oil-satu-rated cores as well as in initially brine-saturated cores at room andreservoir temperatures.

Acknowledgments

The authors wish to thank Maersk Oil Management and Qatar Pe-troleum for permission to publish this work. The authors alsothank Deepa Subramanian and Nora May of Yale University forthe TAN and TBN measurements.

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3 4 5 6 0 1 2


3 4 5 6

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Brine

100 ppm DEM

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100 ppm DEM

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ctio

n P

ress

ure

(psi

g)

Fig. 12—Injection pressure profiles and crude recovery in Tests 7 and 8. Purple represents the results of Test 7 (Brine SW, 105-mdcore); red represents the results of Test 8 (100 ppm DEM in Brine SW, 57-md core). Injection rate 5 5 PV/D. At late stage, the injec-tion rate is increased to 15 PV/D.




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Abbas Firoozabadi is the director of the Reservoir EngineeringResearch Institute (RERI) in Palo Alto, California, USA, and aprofessor at Yale University in Newhaven, Connecticut, USA.His main research interests are in bulk-phase, irreversible andinterfacial thermodynamics, molecular modeling, and physics

and mathematics of hydrocarbon reservoirs and production.Firoozabadi’s honors and awards include the Anthony J. LucasGold Medal of SPE/AIME and membership in the US NationalAcademy of Engineering. He holds a BS degree from AbadanInstitute of Technology, Iran, and MS and PhD degrees fromthe Illinois Institute of Technology, Chicago, USA. All degreesare in natural-gas engineering.

Minwei Sun has been a researcher for enhanced oil recovery(EOR) and flow assurance with Reservoir Engineering ResearchInstitute since 2010. His research interests are interfacial chem-istry, colloids, surfactants, polymers, and nanomaterials. Sunholds an MS degree in materials science from Tsinghua Univer-sity and a PhD degree in chemical engineering from the Uni-versity of California, Riverside. He has coauthored more than20 publications and is the coholder of four patents.

Kristian Mogensen has been a technical adviser for EOR withEni since 2014. Previously, he worked for 16 years for Maersk Oilin Denmark as well as in Qatar. Mogensen holds MSc and PhDdegrees in chemical engineering, both from the Technical Uni-versity of Denmark; has coauthored more than 30 publica-tions; and is the coholder of 20 patents. He is an associateeditor for Journal of Petroleum Science and Engineering anda technical editor for SPE Reservoir Evaluation & Engineering.

Martin V. Bennetzen is senior reservoir engineer at Maersk Oil.He earned MSc and PhD degrees from University of SouthernDenmark. In 2010, Bennetzen received the “EliteResearchAward” from the Danish Ministry of Science, and in 2012, hejoined Maersk Oil. In 2014–2015, Bennetzen held the position asEOR Team Leader at Maersk Oil Research & TechnologyCentre in Qatar, and in 2015, he joined the Maersk Oil Corpo-rate Headquarters. Bennetzen works on EOR, EOR reservoirsimulation, and field-development planning. He is an authoron 28 publications and 12 patent applications within the fieldof EOR. Bennetzen is an associate editor of the Journal of Pe-troleum Science and Engineering.




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