nanofluids cesi paper
TRANSCRIPT
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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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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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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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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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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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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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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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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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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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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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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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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.
References
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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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