The document summarizes bottle tests conducted to evaluate emulsion breakers for treating emulsions resulting from an alkaline, surfactant, polymer (ASP) enhanced oil recovery (EOR) pilot project in Asia. Various mixtures of ASP solution, crude oil, and produced water were created and treated with different emulsion breakers. The tests evaluated the effects of emulsion breaker type and dosage, fluid mixing, temperature, and other factors on emulsion separation rates and water quality. Overall the tests aimed to identify effective emulsion breaker chemistries and dosages for treating emulsions caused by ASP chemical breakthrough at the pilot site.

1. SPE-174659-MS
The Influence of Chemical EOR on Produced Water Separation and Quality
Anton Kaiser, Alan White, Andi Lukman, Istiyarso I, Martin Gernand, Hadi ShamsiJazeyi, Jonathan Wylde,
and Lourdes Alvarez, Clariant Oil Services
Copyright 2015, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Enhanced Oil Recovery Conference held in Kuala Lumpur, Malaysia, 11–13 August 2015.
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 been reviewed 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, its officers, 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 to reproduce 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 use of alkaline surfactant polymer flooding techniques is becoming more commonplace, particularly
in projects where heavier and more viscous crude oil is produced. While the efficacy of increasing
recovery factors cannot be disputed, often there is little consideration given to the implications of these
EOR chemicals breaking through into producer wells and entering the produced water handling system.
The impact caused by EOR chemical breakthrough can be varied, but most commonly the efficacy of
oil/water separation is seriously affected. The contribution that EOR chemicals can have on reservoir
souring is often underestimated, as is the effect they can have upon standard production chemicals such
as scale and corrosion inhibitors. The following paper discusses the oil in water and water in oil emulsion
issues during an alkaline surfactant polymer flooding pilot in Asia.
Introduction
During the application of chemical enhanced oil recovery (EOR) floods, breakthrough of the injection
chemicals periodically occurs resulting in stable emulsions. It is generally challenging to predict exactly
when chemical breakthrough will occur, and flood designs try to eliminate this unwanted event from
occurring. Some EOR recommendations use a combination of surfactant and polymer (SP), alkaline,
surfactant and polymer (ASP), and variations on these two themes. In the event of chemical breakthrough,
it is critical to have processes in place that can handle the ever changing conditions that evolve during the
course of crude oil recovery. The emulsions from such floods can yield both stable water-in-oil (normal)
and oil-in-water (reverse) emulsions particularly if the return of injection chemicals is higher than
expected.
ASP flooding involves injection of a predetermined volume of ASP chemicals into the reservoir, in
order to enhance oil recovery through reduction of Residual Oil Saturation (ROS) and enhancing sweep
efficiency of the system. The surfactant, with its Interfacial Tension (IFT) reduction effects, reduces the
ROS of the system, and the polymer, through its mobility control effects, increases sweep efficiency.
Alkali protects the surfactant from being adsorbed, and also supplements the IFT reduction process,
through saponification of the natural acids in the oil. ASP flooding has proved to increase oil recovery in
many field trials globally. Several ASP pilots of different scales are reported to have yielded net
incremental recovery factors in the range of 15% to 25% over waterflooding.

2. All physical factors listed previously that enhance oil recovery, can also greatly contribute to the
formation of very stable emulsions which are ultimately quite different from naturally occurring emul-
sions which tend to be stabilized by components such as asphaltenes and resins. Traditional emulsion
breakers are often not effective on emulsions created by chemical floods. Like any emulsion, these
induced (i.e. basically synthetic) EOR-based emulsions need to be resolved or broken. Producing dry oil
and clean water are requirements that all producers must achieve. Dry oil is needed to meet pipeline and
various other transportation specifications, whilst clean water is required to meet environment regulations
and operators’ own production needs.
The following paper describes the emulsion breaker selection as part of the final stages of commis-
sioning an ASP EOR pilot project in Asia. The main separation study was done at the EOR lab of the EOR
pilot plant. Further work was performed at Clariant’s global oilfield development labs.
Field and Treatment System
The production volumes of the current process system are 160,000 BOPD and 206,000 BWPD. Most of
the 100ϩ wells are produced using jet pumps driven by produced water or power water; this increases the
water handling to 400,000 BWPD. Only 20 of the total producing wells are ESP.
The crude oil has an API of 31° and a Pour Point of 35 to 38°C; the Wax Appearance Temperature is
51°C. The production header temperature at the different well pads is between 48 and 67°C. Emulsion
breaker chemical is injected to the production header at the well pads and also at the trains.
There are 5 production trains, each consisting of a slug catcher (inlet 70% water cut (WC), outlet
10%WC), a heater (outlet approx. 85°C) and a production separator (outlet 10%WC); all trains feed three
settling tanks. Furthermore, there are electrical dehydrators downstream of each of these tanks. The total
retention time for the water separation is about 10 hours.
The biggest challenge in the process is the quality of the separated water. Due to high throughput in
the 5 trains the interface level of the slug catchers are low resulting in high residual oil in water (OiW)
levels (~200ppm OiW) at the water outlets. The production separators and the settling tanks are able to
achieve low OiW (on average 18ppm). Some of the produced water is injected into disposal wells, the
remainder is used as power fluid for the jet pumps. Additional water is imported from water wells.
EOR Pilot
The EOR pilot consists of 4 injection wells and one producer. The produced fluids are treated in a separate
process train consisting of a sand separator, a mid pressure separator, a dehydrator and a degasser, before
being stored in an export buffer tank which also receives additional oil trucked in from other parts of the
field. All fluids are exported to the main plant for further treatment. Emulsion breaker is injected
downstream of the pilot producer wellhead (25 to 100ppm).
During the test work, emulsion breaker no emulsion breaker was injected and no separation was taking
place at the EOR process train.
The fluid flow from injection wells to the producer well takes approximately 4 weeks.
Experimental – Materials
Oil and Produced Water
Wellhead samples from the pilot producer gave water cuts of Ͼ99% and the ESP did not run continuously
during the testing period. No emulsion breaker injection and no water separation was taking place in the
process train where the crude oil emulsion from the EOR pilot is treated. Sufficient crude samples could
be taken from the degasser, downstream of the process dehydrator. All upstream sample points such as
the MP separator oil outlet or the dehydrator oil outlet showed a very high water cut. Another sample point
from the export of the process train contained trucked in crude from different parts of the field. Due to
2 SPE-174659-MS

3. the fact that the production of the pilot producer was between 0 and 150 bbls per day the crude in the
degasser was several days old. Produced water was taken from the wellhead of the pilot producer.
Chemicals
The EOR Lab at the pilot plant provided the polymer and ASP solutions for the test work. The polymer
solution contained 3000 ppm polymer. The ASP solution contained 3000 ppm polymer, 2.5% Na2CO3 and
2 different sulfate surfactants.
The ASP fluid was used both, unsheared and sheared by an Ultra Turax mixer with S25 NK-19G
dispersing tool for 1 hour.
Emulsion breaker samples were used neat and also as 10% solutions in toluene.
The currently applied emulsion breaker and a second emulsion breaker, which was previously
recommended were available for comparison testing.
Synthetic Emulsion
All synthetic emulsion was produced inside the individual test tubes by shearing for 1 minute using an
Ultra Turax mixer with S25 NK-19G dispersing tool.
Bottle Test Procedure
Test Equipment
Test Procedure
1. Fill the separation bottles with the required ratio of Polymer/ASP fluid/produced water
2. Place the bottles in a 60°C water bath and allow the fluids to equilibrate to the target temperature
3. Fill the separation bottles up to 100 mL with the crude oil emulsion
4. Place the bottles in a 60°C water bath and allow the fluids to equilibrate to the target temperature
5. Shear with the Ultra Turax mixer to prepare the emulsion
6. Inject the required amount of emulsion breaker
7. After dosing all bottles put them into the shaking rack and mix for the required time
8. Place the bottles in the water bath and monitor the water drop for the test duration (for 80°C test,
increase the temperature of the water bath)
9. Make and record observations on separation as well as the interface and water quality
Residual Emulsion, Top cut
This procedure is used at the end of the bottle test in order to assess the efficiency of the emulsion breaking
process. The residual water and emulsion is measured in the treated top oil from the separation bottles.
By using an adjustable cannula the top oil can be taken from different levels.
Test Equipment
Bottles 100 mL graduated test tubes with screw top
Emulsion breaker Injection Brand 10-100 ␮L digital pipette
Injection Rate 50 to 400 ppm (on total fluids)
Injection Temperature 60°C
Emulsion breaker Mixture 100 shakes by hand
Test Temperature water bath at 60°C and then 80°C (see below)
Test Duration 15 to 21 hours
SPE-174659-MS 3

4. Test Procedure
1. Fill the Centrifuge tubes with solvent to 50%
2. Take top oil sample at 80% level and fill centrifuge tubes to 100%
3. Shake tubes to solve the oil completely and heat for 1minute in a hot water bath
4. Centrifuge
5. Record visible emulsion and water % (BS&W)
6. Add 2 drop of “knock out” emulsion breaker and shake again
7. Heat the the tubes for 1minute in a hot water bath
8. Centrifuge
9. Record visible water %
10. In the case of continuing visible emulsion / interface layer, add 4 drops of conc. HCl, mix and heat
for 1minute in the water bath
11. Centrifuge
12. Record visible water %
Viscosity Measurements
Viscosity measurements were performed on ASP fluid before and after bottle testing. Separated water was
taken out of the test bottle using a Socorex syringe and cannula from the 20 to 30% level. For the viscosity
measurements a Brookfield rheometer was used at 6 RPM (7.2 1/s shear rate) and at 75 RPM (91.2 1/s
shear rate) for low viscosity fluids.
Deoiler Bottle Test
Test Equipment
Test Procedure
1. Fill the bottles to the 100 mL mark with the reverse emulsion.
2. Place the bottles in a 65°C water bath.
3. Inject the required amount of deoiler.
4. After dosing all bottles give them all 100 shakes by hand.
Syringe Socorex 10 mL with adjustable cannula
Tubes CMS 12.5 mL graduated centrifuge tubes
Chemicals knock out emulsion breaker, conc. HCl, Toluene
Dosage 2 drops and 4 drops respectively
Centrifuge modified heated 8 place Hettich centrifuge
Duration/Speed 10 minutes at full speed
Emulsion: 500/3000 ppm ASP 90/99% water cut Bulk sample created
@ 65°C using Ultra Turax Shear Stirrer for 1 minute
Bottles 6oz graduated flat bottles with screw top
Deoiler Injection Drummond 10 to 100 ␮L digital pipette
Injection Rate 200 to 1000 ppm (on total fluids)
Injection Temperature 65°C
Deoiler Mixture 100 shakes by hand
Test Temperature water bath at 65°C
Test Duration 10 minutes
4 SPE-174659-MS

5. 5. Place the bottles in the water bath and make observations on the separation and water quality.
Results and Discussion
On Site Bottle Tests
The following list shows all bottle tests (BT) with a brief description about the fluids and conditions used:
All bottle test sheets, separation speed and residual emulsion graphs and photos of the test bottles can
be found in the attachment.
BT1 and BT2
Depending on the amount of water, the emulsion broke immediately at low temperature. Injection of
demulisfier improved the separation speed. Separated water was clean, with and without emulsion
breaker. Top oil quality without demulisfier was below 1% BS&W after 2.½ hours; addition of emulsion
breaker improved the top oil quality at higher water cut ratios. BT1 test bottle no. 7 was an initial test for
a 50% ASP / 50% crude oil emulsion without emulsion breaker; results and can be compared to BT3
which used the same conditions but with emulsion breaker.
BT3 and BT3a
Mixtures with 50% ASP / 50% crude oil emulsion were prepared and compared with no.7 from BT1 (50%
ASP / 50% crude oil emulsion without emulsion breaker). The separated water was oily. The currently
used emulsion breaker 1 appeared to improve the water quality with increased dosage rate; the currently
BT1: Crude mixtures with produced water 10 to 90% without emulsion breaker, separation at 60°C, mixture hand shaken.
BT2: Crude mixtures with produced water 10 to 90% with 100 ppm incumbent emulsion breaker, separation at 60°C, mixture hand shaken.
BT3: 50% ASP fluids/50% crude emulsion mixtures, currently used emulsion breakers 1 and 2 at different dosages, separation at 60°C, mixture
hand shaken, (ASP not pre sheared).
BT3a: The above mixtures with different content of HCl to pH 1 to 2, separation at 60°C, mixtures hand shaken.
BT4: 30/70, 50/50 and 70/30 mixtures polymer fluids/crude emulsion (polymer fluid not pre-sheared), currently used emulsion breakers 1 and 2,
separation at 60°C, one portion hand shaken, the other half mixed with Ultra Turax.
BT5: 30/70, 50/50 and 70/30 mixtures ASP fluids/crude emulsion (ASP fluid not pre-sheared), currently used emulsion breaker 1 at two dosage
rates, separation at 60°C, half were hand shaken, the other half mixed with Ultra Turax (1min 20,000 RPM).
BT6: 30/70, 50/50 and 70/30 mixtures ASP fluids/crude emulsion (ASP pre sheared 1hr at 20,000 RPM), currently used emulsion breaker 1 at
two dosage rates, separation at 60°C, half were hand shaken, the other half mixed with Ultra Turax (1 min 20,000 RPM).
BT7: 30/70, 50/50 and 70/30 mixtures polymer fluids/crude emulsion (polymer fluids pre-sheared 1hr at 20,000 RPM), currently used emulsion
breaker 1at two dosage rates, separation at 80°C, half were hand shaken, the other half mixed with Ultra Turax (1 min 20,000 RPM).
BT8: 50/50 mixtures ASP fluids/crude emulsion (ASP pre sheared 1 hour at 20,000 RPM), in-house EOR emulsion breaker base kit screening,
separation at 80°C, mixtures hand shaken.
BT9: 30/70, 50/50 and 70/30 mixtures ASP fluids/crude emulsion (ASP pre sheared 1 hour at 20,000 RPM), currently used emulsion breaker 1
at two dosage rates, separation at 80°C, half were hand shaken, the other half mixed with Ultra Turax (1 min 20,000 RPM)
BT10: 50/50 mixtures ASP fluids/crude emulsion (ASP pre sheared 1 hour at 20,000 RPM), in-house EOR emulsion breaker bases mix ϩ in-
house finished product EOR kit screening, separation at 80°C, mixtures hand shaken.
BT11: Mixtures of ASP fluids/crude emulsion (ASP pre sheared 1 hour at 20,000 RPM) from 10/90 to 90/10 ratio, no emulsion breaker,
separation at 80°C, mixtures hand shaken.
BT11a: 30/70, 50/50 and 70/30 mixtures ASP fluids/crude emulsion (ASP pre sheared 1hr at 20,000 RPM), currently used emulsion breaker 1 at
100 ppm, separation at 80°C, first set, emulsion hand shaken then emulsion breaker injected, second set, emulsion breaker injected into
crude oil first then emulsion hand shaken.
BT12: 50/50 mixtures ASP fluids/crude emulsion (ASP pre sheared 1 hour at 20,000 RPM), in-house EOR emulsion breaker bases mix screening,
separation at 80°C, mixtures hand shaken.
BT13: 70/30 mixtures ASP fluids/crude emulsion (ASP pre sheared 1 hour at 20,000 RPM) ASP fluid diluted from 3% down to 0,5% Soda ash
with produced water, with and without emulsion breaker, separation at 80°C, mixtures (sheared 1 hour at 20,000 RPM).
BT13a: Mixtures of ASP fluids/crude emulsion (ASP pre sheared 1 hour at 20,000 RPM) from 10/90 to 90/10 ratio, no emulsion breaker,
separation at 80°C, mixtures hand shaken.
BT14: 50/50 mixtures ASP fluids/crude emulsion (ASP pre sheared 1 hour at 20,000 RPM), in-house EOR emulsion breaker bases mix screening,
some blends with different dosage rates, separation at 80°C, mixtures hand shaken.
SPE-174659-MS 5

6. used emulsion breaker 2 had the reverse effect, giving better water quality at lower dosage rates. For both
emulsion breakers, the top oil quality was far away from specification.
The same test bottles were dosed with conc. HCl at 4000 ppm, 1.2% and 2% to see the effect on the
water quality. Test bottle no. 7 was dosed with HCl down to pH 1 - only at this pH could a significant
improvement in water quality be seen.
BT4
BT4 shows the separation behaviour displayed by mixtures of a 3000 ppm polymer fluid and a crude oil
sample from the pilot producer well at different ratios. The polymer fluid was not pre sheared. Only the
30% polymer fluid / 70% crude emulsion mixture sheared with the Ultra Turax showed a slower
separation; all other mixtures separated quickly when shaken or sheared. The currently used emulsion
breaker 1 and the currently used emulsion breaker 2 did not significantly improve the separation. The top
oil quality after 15 hours did not show significant differences between the mixtures.
BT5
BT5 shows the separation of mixtures of ASP fluid and a crude oil sample from the pilot producer. The
ASP fluid was not pre sheared. The viscosity of the separated water was measured after the test with the
Brookfield rheometer; viscosity was found to be 7.2 s-1
at 60°C.
The 30% ASP fluid / 70% crude emulsion mixture when shaken had a lower viscosity than the initial
ASP fluid. The 50% / 50% mixture had similar viscosity and the 70% / 30% mixture had a higher viscosity
than the original ASP fluid.
The sheared mixtures all had significantly lower viscosities in the separated water. Depending on the
amount of ASP fluid mixed, the Top Cut (TC) quality was always worse when the mixtures were sheared
rather than shaken. The currently used emulsion breaker 1, displayed a negative effect at increased dosage
rates. The separation speed did not improve with the addition of emulsion breaker compared to the blank
samples. Like the TC, the water quality was significantly worse at the higher ASP ratios.
In addition to graphs and photos of the test bottles the top cut is shown below for the three groups after
slugging and also after addition of HCl.
Figure 1—BT3a, no 7 to 11, No. 7 (far left bottle) pH 1; No. 8 to 11 2%HCl
6 SPE-174659-MS

7. BT6
BT6 was the repetition of BT5 but the ASP fluids were pre-sheared. Faster separation was seen with 70/30
ASP / crude mixtures compared to BT 5 (non pre-sheared ASP); this was probably because of lower
viscosity. It was observed that the turbidity of the separated water increased with higher ASP solution
content. There was no clear picture about the influence of the currently used emulsion breaker 1.
Sometimes the blank gave better separation, other times the emulsion breaker increased the speed; a
similar trend was seen with the TC.
BT7
BT7 was a repetition of BT4 but at the higher separation temperature of 80°C and with pre-sheared
polymer fluid. There was no separation observed in this test with the 30/70 ASP / Crude mixtures. A type
of flocculation was seen in the separated water of the 50/50 and 70/30 mixtures. It is possible that this was
polymer agglomerate. The Oil in Water (OiW) of the 50/50 and 70/30 mixtures was very low and the TC
of these mixtures (shaken or sheared) showed no increase in residual emulsion. The separation was very
fast. The currently used emulsion breaker 1, was seen to increase the separation with the 50/50 and the
70/30 mixtures.
BT8
BT8 was the first screening test for the developed in-house EOR emulsion breaker bases. For this, the 50%
ASP pre sheared / 50% crude oil emulsion (hand mixed) was chosen. An 80°C separation temperature was
used.
The results shown in Figure 4 indicate that different emulsion breaker bases had only a very small
influence on the separated water quality.
Figure 2—Top Cut slugged (k-o EB) 70% ASP fluid / 30% crude emulsion
Figure 3—Same Top Cut with 4 drops HCl shaken and centrifuged again
SPE-174659-MS 7

8. BT9
BT 9 was a repetition of BT 6 but at the higher separation temperature of 80°C. Again there was poor
separation with the 30/70 ASP / crude mixtures. The 30/70 sheared mixtures separated faster than hand
shaken mixtures. The 50/50 mixtures both separated quickly and gave reasonable water quality. The 70/30
mixture, as seen in all tests before, gave grey water and the high levels of emulsion in the TC. The water
quality was better at 80°C than it was at 60°C.
Figure 4—50% polymer sheared / 50% crude oil emulsion, nos. 7 to 9 hand shaken, nos. 10 to 12 sheared for 1 minute with UT
Figure 5—BT 6 50% ASP / 50% crude mixtures at 60°C
8 SPE-174659-MS

9. BT10
BT10 was another test for screening the specifically developed in-house EOR emulsion breaker bases on
the 50% ASP pre-sheared / 50% crude oil emulsion, which were then hand mixed. Separation temperature
was 80°C.
The main target of this test was the identification of emulsion breaker bases that gave the lowest
residual emulsion in the TC.
BT11
For BT11 additional crude oil emulsion from another producer was mixed with crude from the EOR pilot
producer.
Figure 6—BT 9 50% ASP / 50% crude mixtures at 80°C
Figure 7—BT11 Mixture from left to right; 10% ASP / 90% crude emulsion, up to 90% ASP / 10% crude oil emulsion, after 15 hour
separation at 80°C.
SPE-174659-MS 9

10. With up to 40% ASP / 60% crude oil emulsion, the residual emulsion was low after 15 hour separation
without emulsion breaker.
BT11a
For test bottles nos. 11 to 13 the emulsion was shaken prior to the emulsion breaker injection. For test
bottles nos. 14 to 16 the emulsion breaker was injected to the crude prior to the ASP being mixed in. The
initial separation and TC oil quality was better for nos. 14 to 16 with the early emulsion breaker injection.
No influence on the water quality was observed.
BT12
BT12 is another test to screen the specifically developed in-house EOR emulsion breaker bases and blends
on a 50% ASP / 50% crude mixture.
BT 13
For BT 13 the influence of different dilutions of the ASP fluid was tested. For the 70% ASP / 30% crude
emulsion mixtures, the ASP solution was diluted from 3.0% Soda ash down to 0.5% in 0.5% steps. The
dilution was tested with and without emulsion breaker chemical.
The immediate chemical reaction of the ASP fluid with the crude oil is shown in figure 10. 70 mL of
each ASP dilution was heated to 70°C and then topped with 30 mL crude emulsion; no additional shaking
Figure 8—BT11, residual emulsion at 15 hours
Figure 9—BT11a Bottles 11(left) to 16 after 1 hour. Nos. 14 to 16 had emulsion breaker injected into the crude prior to mixing
10 SPE-174659-MS

11. was done. From 3% down to the 1.5% Soda ash the oil seemed to be completely emulsified; at lower levels
the fluids separated easily.
Figure 10—BT 13: Effect of alkaline concentration on separation
Figure 11—BT13 ASP dilution / crude mix separation trends with and without emulsion breaker
SPE-174659-MS 11

12. Emulsion breaker did not have a significant influence on the separation speed but did affect the top oil
quality.
BT13a
BT13a was a repetition of test 11 without additional crude from another producer. ASP / crude ratios from
10/90 up to 90/10 were used. No emulsion breaker injected, emulsion was hand shaken.
The separation speed was not linear with the ASP content. Figure 14 shows the separation in relation
to the total water content.
Figure 12—BT 13 ASP dilution / crude mix residual BS&W in Top Cuts with and without emulsion breaker
Figure 13—BT13a. Range of ASP / crude ratios. No emulsion breaker addition
12 SPE-174659-MS

13. It is shown that the slowest separation occurs with 20% and 30% ASP, fastest with 50% and 60% ASP.
The same trend was seen with the residual emulsion in the Top Cuts. Lowest residual emulsion was seen
using 50% and 60% ASP. Significantly higher residual emulsion was seen with 20% and 30% ASP;
highest residual emulsion from 70% and 80% ASP. (90% may have had free water).
BT 14
BT 14 was the last test based on 50% ASP / 50% crude emulsion with Clariant in-house EOR emulsion
breaker bases / base combinations. The influence of higher emulsion breaker dosages was also tested.
The specifically developed in-house EOR emulsion breaker bases / base combination kit screening
demonstrated that separation of the water / ASP fluids from the oil for the producer well appeared not to
be too much of a challenge as a number of different chemistries were seen to demonstrate a positive effect.
Figure 14—BT13a Water separation vs time for a variety of ASP / crude ratios
Figure 15—BT13a Residual emulsion
SPE-174659-MS 13

14. From the tests performed, the best EOR emulsion breaker formulation was EOR EB 13094. Most
developed EOR emulsion breaker products gave good water separation but EOR EB 13094 was also seen
to give low levels of residual water and emulsion in the oil Top Cuts at the end of the test. It was also
noted that the separated water quality was better with EOR EB 13094 than it was with other chemistries
tested. That being said, water quality was still fairly poor overall so it will be necessary to use a deoiler
to treat the water separated by the emulsion breaker.
Deoiler Bottle Tests
Deoiler test work was performed using synthetic brine, with crude oil from the EOR pilot producer well
and concentrated ASP fluid.
The objective of the work was to identify chemistry types that demonstrated a positive effect on water
quality when dosed into a synthetic reverse emulsion created from the separate brine, oil and ASP fluids.
When sheared with an Ultra Turax shear stirrer it was found that the fluids form a very stable reverse
emulsion; the untreated blank samples always showed little or no separation throughout the test program.
Initial screening of in-house EOR deoiler chemistries was performed using synthetic brine dosed with
700 ppm of the concentrated ASP chemical. This was based on worst case estimates for ASP. The
emulsion was created using 1% oil and 99% brine / ASP solution. Further tests were performed using 1000
and 2000 ppm ASP chemical in the brine and 10% oil content. This was to study product performance in
the most extreme conditions.
A number of products were seen to give significant water quality improvement when used to treat the
synthetic reverse emulsion, with a couple of standout chemistries.
Figure 16 shows a screening test; the far left bottle was EOR R-EB 13133 at 400 ppm. The Blank was
far right. Other products showed less significant effects (picture taken after 2 minutes).
Figure 16—Deoiler screening. ASP 700 ppm, Oil 1%
14 SPE-174659-MS

15. Bottles 3 and 5 (from left) were EOR R-EB 7979 and EOR R-EB 13133 respectively, both at 600 ppm.
EOR R-EB 13133 can be seen to have left a smaller emulsion layer. EOR R-EB 7958 (second from left)
also showed good effect. Again, far right bottle was the Blank.
Doses (from left) were 100, 200, 400, 600, 800 ppm. Far right was Blank. Very clean water started at
400 ppm. It was noticeable that increasing the dosage higher than this also led to an increase in the
emulsion layer which was taken to be a sign of overtreatment.
Figure 17—Further screening. ASP 700 ppm, Oil 1%.
Figure 18—Ratio test of EOR R-EB 13133. ASP 700 ppm, Oil 1%.
SPE-174659-MS 15

16. Bottle no.2 (from left) was EOR R-EB 13133 at 800 ppm. Other candidates were unable to give
effective treatment under these conditions although all were seen to have some effect when they were
compared to the Blank (far right). The separated oil for EOR R-EB 13133 was seen to be black with only
a thin layer of brown emulsion left on the top.
The results seen from the deoiler testing were very promising; they indicate that specifically developed
in-house EOR reverse emulsion breakers are able to mitigate the reverse emulsion that is expected to be
produced by ASP pilot projects. The tests have shown that EOR R-EB 13133 is a very good candidate to
treat the water that will be produced by the ASP pilot producer well. It is anticipated that using EOR R-EB
13133, in combination with EOR EB 13094, should mitigate the emulsion issues that are associated with
the ASP EOR project on this oilfield in Asia.
Conclusions
An EOR fluid separation study was conducted for an ASP pilot in Asia. Various mixtures of produced
water, polymer fluids and ASP fluids with crude oil emulsion from the EOR pilot producer well were
mixed. The separation behavior of these crude oil mixtures was evaluated at different emulsion mixing
intensities, different temperatures and emulsion breaker dosage rates.
It is clear from the results that ASP fluids will have a significant influence on the separation behavior
of the produced fluids and especially on the quality of the separated water. The currently in use emulsion
breaker will not be able to handle the emulsion changes caused by the ASP breakthrough. The extent of
the effect will depend on the concentration of ASP in the produced fluids as well as the ratio of oil to water
and the amount of shear that the mixture is subjected to. The drastic changes of the oil to water and
chemical ratios that occur during the formation of an oil bank in the reservoir will create challenging
emulsion resolution issues during the treatment of the breakthrough fluids. It seems obvious that a 24/7
field support and subsequent continuous chemical optimization of the emulsion breakers would be
required to ensure trouble-free oil production.
The work done to evaluate the specifically developed in-house EOR emulsion breaker chemistries was
performed on mixtures of ASP fluid and crude oil emulsion from the ASP pilot producer well. The main
objective was fast water separation, low residual emulsion and clean separated water. In addition, the goal
was to develop a chemistry that is able to treat the continuously changing emulsion during the chemical
breakthrough. The test work showed that EOR EB 13094 seems to be able to ultimately resolve these
water in oil emulsion issues. It is clear from the results that EOR EB 13094 can provide sufficient water
Figure 19—Extreme conditions: 2000 ppm ASP, 10% oil.
16 SPE-174659-MS

17. separation and low residual emulsion however it will not give sufficiently clean separated water on its
own. In order to achieve good water quality it will be necessary to use a combination of water in oil
emulsion breaker and oil in water emulsion clarifier / deoiler.
The deoiler test work has demonstrated that the specifically developed in-house reverse EOR emulsion
breaker chemistries are able to mitigate the reverse emulsions anticipated to be produced by the ASP pilot
even at dynamically changing fluid ratios. EOR R-EB 13133 was seen to provide good separation when
applied to a synthetic ASP emulsion, resulting in visibly clean and clear water.
The use of both EOR EB 13094 and EOR R-EB 13133 should enable the production of both dry oil
and clean water at this particular ASP pilot project when ASP containing fluids begin to appear from the
producing well. Further product optimization needs to take place using “live” fluids straight from the well
once the breakthrough occurs. 24/7 field support is highly recommended during breakthrough of the ASP
fluids. Further work needs to be conducted to develop multifunctional water in oil / oil in water emulsion
resolution product packages.
References
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