Nanofluids CESI Paper

7/24/2019 Nanofluids CESI Paper

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SPE 154308

Nanofluid System Improves Post Frac Oil and Gas Recovery in HydrocarbonRich Gas ReservoirsGlenn Penny, Andrei Zelenev and Nathan Lett CESI Chemical Inc. and Javad Paktinat and Bill ONeil Trican WellService

Copyright 2012, Society of Petroleum Engineers

This paper was prepared for presentation at the Eighteenth SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 1418 April 2012.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not beenreviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission toreproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

The primary purpose of using surfactants in stimulating hydrocarbon rich gas reservoirs is to reduce

interfacial tension, and/or modify contact angle and reservoir wettability. However, many surfactants

either adsorb rapidly within the first few inches of the formation, or negatively impact reservoir

wettability, thus reducing their effectiveness in lowering capillary pressure. These phenomena can result

in phase trapping of the injected fluid adversely impacting oil and gas production.

This study describes experimental and field studies comparing various common surfactants used in oil

bearing formations including alcohol ethoxylates, EO-PO block copolymers, ethoxylated amines and a

multi-phase complex nano fluid system to determine their impact on oil recovery and adsorptiontendencies when injected through 5- foot and 1 ft sand columns. Ammot cell tests were used to evaluate

imbibition of oil and water and a core flow apparatus was used to evaluate regained relative

permeabilities. The results are correlated with surface energies of actual formation materials, oils and

treating fluids. The results are used to select formulations containing surfactant, solvents and co-solvents

to apply within the fracturing fluid to decrease adsorption, eliminate post treatment emulsions and

improve oil and gas recovery in hydrocarbon rich gas wells.

Introduction

Surfactants should in theory be critically important in either moderate permeability reservoirs for oil orlow permeability reservoirs for gas (tight gas or shale). It has been argued that the surfactant reduces the

capillary pressure of the fluid in the near fracture region thus improving flowback of the fracturing fluid.

The performance of surfactants following hydraulic fracturing is typically evaluated in core flow tests or

in sand packed column tests to look at the impact of the additive on the reservoir rock and the proppant

pack. Oil reservoirs exhibit complex wettabilities that must be understood for each reservoir. Clays line

the pores of most reservoir rock, and in the case of shale, an added complication is the hydrophobic

kerogen partially lining the pore surface. Further, the presence of liquid hydrocarbons may adsorb and

alter the wettability of the reservoir. These factors make it difficult to determine the wettability of the

reservoir.


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In this work several testing methodologies are examined which can be used to predict the performance of

surfactants. These are listed below:

Adsorption. The adsorption of the surfactant is measured by flowing the test fluid through proppant

packs or mixtures of formation and proppant and looking at the surface tension 1,2,3.

Contact Angle. The contact angle with the reservoir rock can be measured from imbibition into cores as

well ascapillaries (Howard et al.)4. In the present work contact angles were measured on shale and on

quartz slides using a contact angle goniometer instrument. Prior to measuring contact angles, rectangular

pieces were cut out of a shale core. The surface was polished to a mirror glaze finish with 2000 grit sand

paper to create a smooth surface. Shale samples and quartz slides were immersed into a glass cell filled

with condensate. A droplet of aqueous solution containing either 3% ammonium chloride brine or the

brine with surfactant was then placed on the surface of the shale or quartz substrate. Contact angles were

measured at the aqueous phase-condensate-substrate interface. In this work the equilibrium contact angle

was established in less than one minute. To achieve a better understanding of the interactions between

fluids and reservoir rocks, the surface free energy of has been determined from contact angle

measurements at the solid/air interface using the method of Fowkes

5

.

Ammot Tests. The improved oil recovery technique to measure wettability is to use an Ammot cell

procedure to imbibe the test fluid into an oil saturated core displacing the oil6. In hydraulic fracturing the

oil must displace the treatment fluid to establish oil flow. This is opposite to the standard Ammot test for

EOR that displaces oil with water .7

Core and Column Flow Tests. Flow tests can be run either direction. In improved oil recovery (IOR) the

water is used to displace the oil. To simulate fracturing the oil or gas displaces the treating fluid in cores

or columns. This work compares the use of the Ammot cell test and the use of oil displacing water in

cores and in columns packed with proppant and formation cuttings.

The question to be answered is simply what test method is the most effective in predicting the

effectiveness of a treatment in improving the flow of oil from the treated formation and proppant pack.

Surfactants

Surfactants selected for testing include: alcohol ethoxylate (AE) a non-ionic C10-12 straight chain

alcohol with various amounts of ethylene oxide (EO). Typically 4 to 9 moles of EO are used in non-

emulsification blends (Figure 1). Nonyl phenol ethoxylates (NP) have been evaluated but are less

favored because of toxicity issues. Polymeric materials include amine alkoxylates and ethylene oxide

and propylene oxide (EO PO) block copolymer demulsifiers (DEM) (Figure 2).

Figure 1. Linear alcohol ethoxylates (AE)

Alcohol ethoxylates can be used

independently or in combination with

demulsifier bases

C10-12 with 4 to 9 moles EO


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Figure 4. Droplet size distribution in a complex nanofluid vs. an emulsion.

Experimental

Adsorption

To evaluate the adsorption of surface active substances in porous media, fluids containing various

surfactants were passed through a chromatography column packed with either sand and/or shale. In a

typical experiment 100 grams of sieved -70/+140 meshgranular material was packed in a 12 inch (25 cm)long by1 inch (2.5 cm) diameter column through which the treatment fluid flowed under gravity. The

pore volume of the packed column was measured by flowing brine. A fluid containing surface active

treatment was then allowed to gravity flow through the column. The surface tension of each pore volume

was measured using the Wilhelmy plate technique4. This was compared to the surface tension of the

same fluid prior to contact with the solid matrix. All tests were carried out at ambient temperature and

atmospheric pressure.

Packed column water displacement tests

A 12 inch (25 cm) long by1 inch (2.5 cm) diameter chromatography column was packed with either sand

or a 50/50 mixture of sand/shale cuttings to simulate sand/shale interface in the fracture. The column wassaturated with the test fluid with and without the various test surfactants. Three pore volumes were

flowed through the column. The brine was drained to the top of the pack and the bottom of the column

was shut in with a clamp. Condensate or oil was poured into the column above the sand pack to a height

of 201 cm. A separatory funnel with a side arm open to the atmosphere was placed at the top of the

column and was filled with condensate to maintain a constant head. To begin the test the clamp was

removed, the timer was started and the effluent from the column was collected into plastic beakers. The

weight of fluid collected was measured vs. time. Data were analyzed in terms of % aqueous phase

recovery and the fractional flow rate of aqueous phase and oil phase as a function of time, as shown in

Figure 5.


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SPE 154308 5

Figure 5. Flow rate of aqueous and oil phases in a typical aqueous phase displacement experiment.

Core flow experiments

Core flow test procedures were conducted on the surfactant based fluid treatment systems using low

permeability cores. The core flow system is shown in Figure 6.

Figure 6. Single core flow holder for measuring relative permeability to oil.

The core flow procedures with oil are as follows:

Measure and record the length and diameter of core sample

Load core into core holder and set conditions to 500 psi confining pressure, 150 psi back pressure,and 100oF. Flow hexane through core in production direction (low rates: 0.2 and 0.4 ml/min) for

minimum of 15 total pore volumes.

Remove core and dry at 106oC overnight, then measure the dry mass.

Reload core orient in same direction as before set test conditions to 2000 psi confining pressure,500 psi back pressure, and 150oF. Ensure all equipment is dry before setting up test and


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pressurize system with dry nitrogen. Establish a dry nitrogen perm in production direction at

three differential pressures.

Unload core and vacuum saturate the core (set overnight in fluid) in API (or selected) brine.

Measure and record the saturated mass.

Reload the core (orient in same direction) setting test conditions to 2000 psi confining pressure,

500 psi back pressure, and 150

o

F. Fill system with API (or selected) brine and establish a brinepermeability in the production direction at two rates.

When complete, the measure the effective permeability to oil in the production direction usingconstant differential pressure and measuring the oil rate passing through the core. Measure the

effective permeability at various desired differential pressures. During the testing if no flow is

detected after 30 minutes at a differential pressure the pressure is then increased to the next

differential pressure. If flow is detected at a differential pressure that pressure is held until an

effective permeability is measured before proceeding to the next differential pressure.

From these results, permeabilities are calculated using the following:

Permeability (md) = 245 * Core Length (cm) * Flow Rate (mL/min) * Fluid Viscosity (cP)Differential Pressure (psi) * Area (cm^2)

The relative permeability is calculated by comparing the perm with oil in the brine saturated core vs. the

nitrogen permeability.

Ammot Cell

The Ammot cell is used to demonstrate the effectiveness of various surfactant solutions in displacing oil

from a core14. The cell is shown in Figure 7 with a 1 inch diameter by 1 inch long core plug in a test

solution. The displaced oil collects in the burette at the top of the vessel.

The Ammot cell procedure is as follows: Vacuum saturate 1 inch diameter cores in crude oil for 24 hours.

Remove cores and allow the surface oil to drain off.

Weigh the cores to determine mass of oil.

Load one Ammot cell with the oil-saturated core and fill with 2% KCl brine and another Ammotcell with brine and the test surfactant.

Put in water bath at 150 F.

Monitor the volume of oil expelled by the core versus time at 1 hr, 3 hr, 6 hr, overnight, 24 hr, 2 days, 3

days, 4 days, and up to 5 days.


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SPE 154308 7

Figure 7. Ammot cell for measuring oil displacement from a core.

The United States Bureau of Mines (USBM) centrifuge test is used in conjunction with the Ammot cell

test to determine wettability. The Amott method (Figure 7) involves four basic measurements. Figure 8

shows the data produced with the water wetting index given by AB/AC and the oil wetting index by

CD/CA.

(i) The amount of water or brine spontaneously imbibed, AB.

(ii) The amount of water or brine forcibly imbibed, BC.

(iii) The amount of oil spontaneously imbibed, CD

(iv) The amount of oil forcibly imbibed, DA

Figure 8 shows the initial conditions of the sample (point X) to be oil saturated at Swi. The

spontaneous measurements are carried out by placing the sample in a container containing a

known volume of the fluid to be imbibed such that it is completely submerged (steps 1 and 3

in Figure 7.3 for water and oil respectively), and measuring the volume of the fluid displaced

by the imbibing fluid (e.g. oil in step 1 of Figure 7.3). The forced measurements are carried

out by flowing the imbibing fluid through the rock sample and measuring the amount of the

displaced fluid (steps 2 and 4 in Figure 7.3), or by the use of a centrifuge. The important

measurements are the spontaneous imbibitions of oil and water, and the total (spontaneous

and forced) imbibitions of oil and water. Water-wet samples only spontaneously imbibe water.


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8 SPE 154308

Figure 8. Ammot wettability test data

Results and Discussion

Dynamic Adsorption Tests

Evaluating the difference in the surface tension of fluids before and after their contact with porous

media provides means for evaluating the loss of surface activity due to surfactant adsorption on the rock

matrix or in the proppant pack. An increase in the surface tension may often serve as an indication that

due to surfactant adsorption the surfactant concentration in the treatment fluid had fallen below the level

necessary to sustain a micellar solution. An increase in the surface tension corresponds to a decreased

effectiveness of the fluid to lower the capillary pressure. The primary method of adsorption evaluation is

surface tension differential measurement of injected fluids. Data interpretation is based on the premise

that when fluids containing surface active substances migrate through a packed column, surfactant loss

from liquid phase due to the adsorption on the solid matrix is enhanced as liquid travels further down the

column. Therefore, in the event of a strong adsorption, one may expect that the surface tension of the

fluid sampled further away from the injection point will be higher than that of fluid sampled close to the

injection point. Also, a number of fluid pore volumes that need to be pumped through a pack in order to

maintain low and constant surface tension can serve as an indicator of the effectiveness of surface active

treatment in preserving low surface tension of the fluid. As illustrated in Figure 9, various surfactant

treatments adsorb to different extents as they pass through the shale pack. This technique also has been


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SPE 154308 9

illustrated in previous work utilizing a longer sand packed column2,3. Surfactants selected for testing

include: a non-ionic C10 straight chain alcohol ethoxylate (AE) with twelve moles ethylene oxide, a non-

ionic complex nano fluid containing linear and branched alcohol ethoxylates, a nonyl phenol ethoxylate

(NP) and ethoxylated alcohol fluorosurfactant (FS) and mixtures of the nanofluid/microemulsion (ME)

and FS. The adsorption tests show that the NP and FS are rapidly adsorbed onto the shale. The surface

tension stays near 70 dynes/cm for several pore volumes before dropping. The AE shows less adsorption

dropping to 40 dynes/cm within 4 pore volumes. The nanofluid which is a microemulsified solvent and

cosolvent with nonionic ethoxylates and water shows that the surface tension drops to the 30 dynes/cm

within 2 to 3 pore volumes. Finally, the combination of nanofluid and 2% FS drops to near 20 dynes/cm

in 3 pore volumes. The formulation of the surfactants into a complex nanofluid allows the surfactant to

travel further into the matrix allowing the surfactant to remain with the leading edge of the penetrating

fluid.

Figure 9. Surface tension vs. pore volume through 20/40 shale and sand columns.

Figure 10. Aqueous phase displacement by condensate in the presence of 0.1, 0.5, 1.0, 2.0, & 10 gpt

nanofluid DEM added to the base 3% Ammonium chloride Brine in a -70/+140 mesh sand column. Red

squares correspond to the time at which oil break-through took place.

0

10

20

30

40

50

60

70

80

0 2 4 6 8

Pore Volumes

SurfaceTension(d

ynes/cm)

2% FS

NP

AE

ME

ME+

2%FS


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10 SPE 154308

Figure 11. Flow rate of aqueous phase at different concentrations of nanofluid DEM additive

corresponding to the same data as shown in Figure 10.

Packed column aqueous phase displacement tests

Figures 10 and 11 show the effectiveness of various concentrations of nanofluid in dewatering packed

sand columns by the displacement of the aqueous phase with condensate oil. These Figures show that the

effectiveness and efficiency of aqueous phase displacement increased with increasing amounts of

nanofluid demulsifier (DEM). The brine/condensate interfacial tension and the brine/quartz/condensate

three-phase contact angle were measured vs. the concentration of nanofluid demulsifier. The results are

shown in Figure 12. Prior to adding nanofluid demulsifier, interfacial tension between brine and

condensate was 12.4 mN/m and the contact angle at the three-phase boundary was 57 degrees. This

corresponds to a water-wet surface. When nanofluid demulsifier was added the interfacial tension was

lowered with each addition and reached 0.29 mN/m at 10 gpt. There is a simultaneous increase in thecontact angle with increasing concentration of nanofluid with the contact angle increasing from 57

degrees in the brine alone to 138 degrees at a nanofluid concentration of 10 gpt. In the test with brine

only the condensate displaced only 15% of aqueous phase. This can be attributed to the high interfacial

tension and low contact angle. Lowering the interfacial tension favors the penetration of oil through a

layer of aqueous phase, while increasing the contact angle converts from a water-wet to an oil-wet

surface and a removal of aqueous phase film from the surface of the sand grains. The relative importance

of these two factors can be seen in Figures 10 and 11: the addition of 0.1 gpt of nanofluid DEM additive

caused a sharp drop in the interfacial tension and a small increase in contact angle, still producing a

water-wet quartz surface. This resulted in an increase in dewatering rate. 35% of the aqueous phase

remained trapped in the column at the end of the experiment. Further increases in additive dose produced

contact angles exceeding 90 degrees, which corresponds to a transition from a water-wet surface to an

0

0.5

1

1.5

2

2.5

3

0 6 12 18 24 30 36 42 48 54 60 66 72 78 84 90 96 102108114120126

FlowRate(g/min)

Time (minutes)

Flow Rate (10gpt) Flow Rate (2.0gpt) Flow Rate (1.0gpt)

Flow Rate (0.5gpt) Flow Rate (0.1gpt) Flow Rate (Brine)


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SPE 154308 11

oil-wet quartz surface favoring the displacement of water. At this condition water displacement reaches

85% in 60 min.

0.1 1 10

40

50

60

70

80

90

100

110

120

130

140

150

160

Contact Angle

InterfacialTension(mN/m)

Contactangle,degrees

Dose of Added nanofluid (gpt)

3% NH4Cl brine / Condensate Oil / Quartz

no nanofluid

additive

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

Interfacial Tension

Figure 12. Interfacial tension at condensate-ammonium chloride brine and contact angle at a three phase contact

line in condensate-brine-quartz system as a function of nanofluid additive dose.

A packed column test was also run with 50/50 Bakken drill cuttings and sand to show the difference

between sand and cuttings. The brine with and without the nanofluid was displaced with Bakken oil as in

Figures 10 and 11. With Bakken cuttings and no surfactants, the recovery efficiency of brine alone

increased from 15% to 45% (Figure 13). The contact angle measured at the three-phase contact line

between condensate, ammonium chloride brine and shale was 122, as opposed to 56 measured forquartz-condensate-brine system. Such a high value of contact angle indicates that the surface of shale

was wetted by oil rather than waterand explains the higher aqueous phase recovery. The data on fluid

displacement is further supported by the difference in the components of surface free energy, S, of

hydrated quartz and shale summarized in Table 1. Surface energy components of Bakken shale were

evaluated from contact angle measurements of probe liquids on polished shale core as described

previously (Zelenev)15, while values for hydrated quartz were found in the literature (Janczuk)16. Oily

dolostone was purchased through the Onta Company in Calgary, Canada. They describe the sample as a

Silurean Gulf formation. It is noteworthy that although dolomite is a major constituent of Bakken shale,

the surface free energy of oily dolostone was closer to that of hydrated quartz, rather than shale (Table 1).

This observation suggests that hydrocarbon content rather than mineralogy may be determining the

wettability of the rock matrix.

Table 1. Lifshitz- van der Waals (LW), Lewis Acid/Lewis Base (AB) components of the surface free energy of hydrated

quartz and Bakken shale.

S(mJ/m2) LW(mJ/m2) S

AB(mJ/m2)

Bakken shale 48.23 48.10 0.13

Quartz w/H2O film 59.06 41.3 17.76

Oily dolostone 56.23 45.74 10.49

Values in Table 1 indicate that in addition to the net surface free energy of shale being lower than

that of hydrated quartz, there is a significant difference between the two substrates in their acid-base


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12 SPE 154308

components of the surface free energy. Such a difference reflects that shale as compared to quartz has a

substantially weaker tendency to interact with liquids via hydrogen bonding, which would mean weaker

wetting of shale surface by brine, and hence easier detachment of aqueous film. Nevertheless, the use of

the nanofluid CnFTM + DEM in a mixed sand/cuttings packed column still increased aqueous phase

displacement efficiency and effectiveness to 70% as illustrated in Figure 13.

Figure 13. Effect of nanofluid additive on aqueous phase displacement by Bakken condensate in a

column packed with 50/50 mixture of -70/+140 mesh Bakken cuttings and sand.

The surface free energy of formation rocks and proppant materials plays a significant role in

determining the impact of surface active additives on two-phase flow in porous media. Figure 14 shows

a comparison between dispersion and non-dispersion components calculated with a different approach as

compared to values in Table 1, (see Zelenev15 for details of surface free energy of typical oil-bearingrocks).

Oily Dolostone Oily Limestone Oily Sandstone Bakken Shale

0

10

20

30

40

50

60

SurfaceFreeEnergy(mJ/m

2)

Total

Dispersion

Non-dispersion

Figure 14. Surface free energy and its dispersion and non-dispersion components calculated with Owens-

Wendt-Raebel-Kaelble approach for samples of different oil-bearing rocks.

010

20

30

40

50

60

70

80

0 100 200 300 400 500

%

WaterRecovered

Time (minutes)

2gpt CnF+DEM

3% NH4Cl


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SPE 154308 13

Results in Figure 14 indicate that the contribution from a non-dispersion component characterizing

relative capability of the surface to interact via dipole-dipole and hydrogen bonding interactions may

substantially vary between different rock matrices. Such large differences are expected to strongly

influence the transitions from water-wetting to oil-wetting conditions, and may predict differences in

surfactant-mitigated wetting in various formations. Detailed studies investigating the relationship

between surface free energies and effectiveness of surfactant treatments in aqueous phase displacement

are presently underway.

The impact of contact angle on the relative permeability of various rock types has been described in

previous literature. For example Figure 15 shows the impact of changing the contact angle on relative

permeability to oil in a sandstone17. In enhanced oil recovery water and surfactant floods the emphasis

has been to water wet the rock to increase the relative permeability to oil. In fracturing it is advantageous

to increase the oil/water/rock contact angle in the invaded region so as to increase the relative

permeability to water. This allows the displacement of the water leaving a lower water saturation and a

higher relative permeability to oil. In Figure 15, by changing the contact angle from near 0 degrees to

138 degrees on sandstone/quartz, the relative permeability to water increases from 0.01 to .05 or a 5 foldincrease at oil breakthrough around a water saturation of 50%. Looking at the column flow data in

Figure 11, the flow rate increased from 0.1 to 0.5 cc/min at oil breakthrough at a constant head by adding

0.2% nanofluid which increases contact angle and decreases interfacial tension.

Figure 15. Impact of contact angle on the relative permeability of oil and water in sandstone.

Several tests have been carried out using formation core that show the impact of oil/water/rock interfacial

phenomenon. These include the Ammot cell test, the centrifuge displacement test and core flow testing.

Ammot cell tests.

Ammot cell tests have been conducted on various surfactants as reported by Dag et al.16. In this work

Ammot tests were conducted on oil saturated Bakken cores as described above. As can be seen in Figure

16, the 2% KCl results in a displacement of 28% of the oil. The nonionic demulsifiers NI DEM 1 and 2

released 38 to 40% of the oil while the Nanofluid DEM released 50%. A nonionic highly nonionic water

wetting surfactant (NIW Wetting) released 58%.

0.01

0.1

1

0 0.2 0.4 0.6 0.8

OilandWaterrelPerm

Water Saturation

0-SS-kro

138-SS-kro

0-SS-krw

138-SS-krw


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14 SPE 154308

Figure 16. Ammot cell tests of Bakken core saturated with Bakken crude oil. The various surfactant

systems were at 0.2%.

Demulsification tests were performed on the same systems with the Bakken crude oil using the method

described by Zhou18. The standard DEM system breaks out 92% of the oil/water emulsion within 10

minutes. The Nanofluid DEM combination breaks 98% of the emulsion within 5 minutes. The water

wetting surfactant breaks very slowly. Thus there is a balance needed between the DEM and the oil and

water of the formation before applying the best material form the Ammot cell test. The Nanofluid DEM

performs second best in the Ammot cell test and is the best in the demulsification test (Figure 17).

Figure 17. Demulsification tests of Bakken crude oil and 2% KCl containing 0.2% of the indicated

surfactant systems.

Ammot combined imbibition and centrifuge test.

0

10

20

30

40

50

60

70

0 50 100 150

PercentOilRecovered

Time (hours)

NIW Wetting

Nanofluid DEM

NI DEM2

NI DEM1

2%KCl

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25

%Demulsification

Time (min)

Nanofluid DEM

DEM

NIW Wetting

Brine


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SPE 154308 15

A series of tests were performed with 1 to 2 mD Bakken cores which were saturated with oil. The cores

were immersed in brine and 0.2% nanofluid for 5 days to evaluate imbibition. The cores were then

subjected to18,000 rpm in a centrifuge for 60 minutes to force displacement. The results are plotted in

Figure 18 for 2% KCl and nanofluid treatment displacing oil and for oil displacing 2% KCl and nanofluid

treatment. The nanofluid treatment is marginally effective at displacing oil. However, oil displaces the

nanofluid treatment very effectively when compared to 2% KCl alone just as it does in the column flow

tests in Figures 10 and 13.

Figure 18. Ammot test combining imbibition and centrifuge forced water displacing

oil and oil displacing water using shale condensate in 1 to 2 mD Bakken cores using 2% KCl with andwithout 0.2% nanofluid. AB is water imbibed/oil displaced in oil saturated core and BC is centrifuge

forced oil displacement. CD is oil imbibed/water displaced in brine saturated core and DA is centrifuge

forced oil displacement as outlined in Figure 8.

Core flow testing.

Core flow tests were performed used 1 to 2 md cores saturated with Bakken crude oil (Figure 19). The

first observation is that the brine is efficiently displaced with the oil providing a relative permeability to

oil of 0.3. The DEM provides slightly higher relative perms to oil at 0.32 while the NanofluidDEM

provided a relative permeability to oil of 0.38. In regained oil permeability terms that is 125% of the base

relative perm.

0%

10%

20%

30%

40%

50%

60%

%OIlorw

aterdisplaced

DA-oil forced

CD-oil imbibed

BC-water forced

AB-water imbibed

Water displacing

Oil

Oil Displacing

Water


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16 SPE 154308

Figure 19. Relative permeability to Bakken oil in 2 mD Bakken cores with 2% KCl and 0.5 gpt DEM

and 1.5 gpt nanofluid DEM.

Conclusions

The conclusions of this work are as follows:

1. Adsorption is an important consideration when surfactants are flowing through formation

cores/cuttings and sand packs. Adsorption can be mitigated by formulating with nanofluids in

place of common surfactants.

2. The efficiency of water displacement with condensate is influenced by both interfacial tension

and changes of wettability of the substrate, and is optimum at an interfacial tension of 1

dyne/cm and non-water wetting conditions, which corresponds to 0.15 to 0.2% of nanofluid

DEM.

3. Surface energy values are useful in predicting wettability of various formations and explaining

the results of aqueous phase displacement studies.

4. Ammot cell tests that show oil recovery must be supplemented with demulsification tests to

optimize composition of formulations for hydraulic fracturing.

5. A combination of a nanofluid and a demulsifier mitigates adsorption, improves demulsification

effectiveness and improves oil flow.

Acknowledgments

The authors would like to thank the management of CESI Chemical, a Flotek company for permission to

publish this work. The authors wish to thank Keith Dismuke of CESI Chemical for his help in the

Ammot cell and centrifuge work.

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0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0 50 100 150 200

RelativePermeabilitytoOil

Time (min)

Nanofluid DEM

DEM

Brine


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SPE 154308 17

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Woodlands April 20-22

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Demulsifier for Well Completions, SPE 121762 presented at the 2009 Oilfield Chemical

Symposium, The Woodlands April 20-22Zelenev, A.S. "Surface Energy of North American

Shales and its Role in Interaction of Shale with Surfactants and Microemulsions", paper SPE

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18 SPE 154308

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with Surfactants and Microemulsions", paper SPE 141459, presented at SPE International

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Documents

Nanofluids CESI Paper