SPE-171120 Smart Water Injection for Heavy Oil Recovery from Naturally Fractured Reservoirs

8/10/2019 SPE-171120 Smart Water Injection for Heavy Oil Recovery from Naturally Fractured Reservoirs

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2 SPE-171120-MS

Introduction

Enhanced Oil Recovery (EOR) methods vary significantly from one type of reservoir to another. Heavy and extra heavy oil

reservoirs are amongst oil reservoirs that usually undergo EOR early in their production life. That is because these reservoirs

rarely produce under natural (primary) recovery mechanisms and sometimes even react inadequately to secondary recovery

methods. Thermal recovery methods (e.g., steam injection) are usually applied to heavy and extra heavy oil reservoirs.

However, steam injection cannot be successfully or economically applied to every heavy oil reservoir. There is therefore agreat interest in developing non-thermal methods for improving heavy oil recovery. Non-thermal methods such as gas

injection have been applied to light (conventional) oil reservoirs across the world with great success. The gas injection EOR

processes have shown good opportunities to revitalize mature oil fields and Naturally Fractured Reservoirs (NFR) around the

world. For instance, CO2 injection has been remarkably successful for improving light oil recovery and also for heavy oils

(Sohrabi et al). However, the cost of gas supply and injection can be prohibitive.

It is widely known that carbonates reservoirs are heterogeneous, essentially fractured, low porosity, with presence of vugs

and sometimes partially dolomitized. These characteristics along with oil-wet conditions result in low recovery factors from

these reservoirs. The initial oil production is produced from and by the fracture systems in the reservoir and the oil in the

matrix remains unaffected. In general, it is difficult to displace the oil located in the matrix blocks into the fractures. For this

kind of reservoirs, thermal EOR methods have been a common use (Manrique et al., 2007-2010). Gas injection has also been

popular in carbonates formations. Water injection in some carbonate reservoirs has led to good recoveries including in NFR.

Under these conditions, the spontaneous imbibition of water from fractures into the rock metrix is the main mechanism of oil

production. North Sea fields are good examples of successful water injection in carbonate reservoirs. Expulsion of the ligh oil

from the matrix as a natural process in presence of sulfates in the injection water has been cited as one of the reason for

change of wettability of carbonate rock to more water-wet enhancing the spontaneous imbibition phenomenon.

The complexity of NFR reservoirs are compounded by high pressure and high temperature conditions. NFR containing heavy

or extra heavy oils would be amongst the most difficult reservoirs to produce from and often leads to very poor reservoir

performance with low recovery factors.

The use of (smart) water injection as a natural wettability modifier has recently gained significant attention. The method is

considered relatively inexpensive and easy to inject even in hostile environments such as high pressure/high temperature or

deep reservoirs. It can also be implemented at any time during the reservoir life. Recent research has shown that ionic

composition (at times, in combination with high temperature above 90 oC), can play a vital role in oil recovery and may yield

up to 85 % of total oil under tertiary recovery mode (Austad et al., 2005-2007; RezaeiDoust et al., 2009; Shariatpahahi et al.,

2010-2011; Tweheyo et al., 2006; Yousef et al., 2010-2011-2012; Zhang et al., 2007-2012). Even though the alteration ormodification of the composition of the injection water has been mentioned by various research groups, the findings and

conclusions are not consistent. For instance, in carbonate reservoirs, smart water worked at high temperatures and about

33,000 ppm total salt content but affected the initial wettability in sandstones when was diluted to much a lower salinity <

5000 ppm. Clearly, other factors such as crude oil composition, rock mineralogy and formation and injected water

chemistries affect the wetting properties of oil reservoirs. Whilst some laboratory and field applications have had successful

outcomes, there are cases in which smart water did not make any significant difference.

Most of the laboratory tests on smart water injection have been conducted with light oils. The studies of smart water as

diluted water injection have been focused on sandstone reservoirs and more recently have been expanded to carbonate rocks

(Austad et al., 2012; Fathi et al., 2011; Romanuka et al., 2012; Strand el al., 2008; Yousef et al., 2010-2011-2012). However,

there are no published reports in the open literature on the application of smart water injection for heavy or extra heavy oils.

This paper is part of a study associated with improving heavy and extra-heavy oil recovery with a special emphasis on NFRat high pressure and high temperature. Seawater was used as the injection fluid due to its favourable characteristics for oil

recovery in this system. Thus, this work focuses on investigating the implementation of smart (seawater and low salinity)

water injection for extra-heavy oil recovery from carbonates rocks at high temperature. Experiments including spontaneous

imbibiton and coreflood tests were carried out under both secondary and tertiary injection modes. Oil recovery, water

composition, and pH measurements before and after the experiments were all performed during the experiments.



SPE-171120-MS 3

Material

Crude oil- An extra heavy oil was used in the experiments. Table 1 shows the basic properties of the crude oil. The total acid

and base number are also presented. The results of the analysis of metal and sulphur content of this crude oil are shown in

Table 2. The crude oil was centrifuged before being used to ensure it was free from solid particles or emulsions.

Table 1. Crude Oil Properties.

Crude

Oil

Density

@ 22 oC

(0API)

Viscosity

@ 22 oC

(cp)

Asphaltenes

Content ( %wt)

Resins

Content (%wt)

Acid Number

(mg KOH/g)

Base Number

(mg KOH/g)

A 12.55 32, 537.99 13.20 31.70 1.00 3.50

Table 2.The metal element contents in the crude oil (mg/kg).

Crude

Oil Al Ca Cu Fe K Mg Na Ni Pb S Si Sr V

A 3.84 5.13 <0.05 0.69 0.85 0.95 4.98 47.42 <1.00 2.31 <1.00 <0.05 217.40

Brine- Systematic experimental results have shown that seawater tends to be an effective type of water for improving the oil

recovery factor in fractured carbonates reservoirs. The existing literature points out that the reservoir temperature and some

specific components of the seawater are essential with regard to weetability changes. Based on these results, five different

brines were used in this study. Brine 1 was synthetic formation water, Brine 2 was synthetic seawater from Gulf of Mexico

whilst Brine 3 and 4 were diluted versions of that seawater, 10 and 50 times dilution, respectively. Brine 5 was a solution of

sodium and calcium chloride (NW). The compositions of the brines used in this study are given in Table 3.

Table 3. Brine compositions.

Ion

FW

(mg/L)

SW

(mg/L)

LSSW10

(mg/L)

LSSW50

(mg/L)

NW

(mg/L)

Na+ 9,614.97 11,429.38 1,142.93 228.58 3,147.00

Ca2+ 320.36 429.60 42.96 8.59 365.00

Mg2+ 218.94 1361.60 136.16 27.23 -

K + - 351.10 35.11 7.02 -

Ba2+ - 0.01 - - -

Sr2+ - 8.37 0.83 0.16 -

Cl- 15,117.25 20,040.00 2,004.00 400.80 5,498.73

SO42- 550.63 3,500.00 350.00 70.00 -

HCO3- 1,135.9 47.58 4.75 0.95 -

pH 8.01 7.80 7.20 6.75 5.35

Viscosity (cp) 1.03 1.07 1.00 0.99 1.01



4 SPE-171120-MS

Cores- Table 4 shows a list of both limestone and dolomite cores used for coreflood experiments at 92 oC. Dimensions were

measured and porosity and brine permeability was also determined by measuring the differential pressure across each core at

different flow rates in a special core holder designed for high pressure and high temperature. Environmental Scanning

Electron Micrscopic (ESEM) revealed that the cores obtained from dolomite rocks contain carbon, oxigen, magnesium,

calcium and small amounts of iron and silicon. Meanwhile, limestone cores contain carbon, oxygen, calcium, and also small

magnesium and silicon concentrations were noted. Figure 1 exhibits the mineralogy of the rocks.

Table 4. Properties of cores used for laboratory experiments.

CoreDiameter

(cm)

Length

(cm)

PV

(ml) (%)

Sw

(%)

K brine

(mD)

Limestone 1 2.55 15.30 16.58 21.21 31,17 6.90

Limestone 2 2.50 9.70 17.91 37.42 28.78 19.51

Limestone 3 2.64 15.20 20.11 24.17 31.57 51.80

Dolomite 1 2.62 15.20 17.04 20.79 36.89 194.32

Dolomite 2 2.60 15.30 21.42 26.37 34.30 345.49

Limestone 4 2.63 15.20 18.55 22.36 33.95 62.77

Limestone 5 2.52 15.2 18.34 24.25 28.30 146.51

Limestone 6

2.52 15.2 15.55 20.64 32.13 19.40

2.52 15.2 15.55 20.64 32.13 19.40

2.52 15.2 15.55 20.64 32.13 19.40

Figure 1. Mineral composition of cores, dolomite (right) and limestone (left).

Factors Affecting Wettability Conditions

In carbonates, wettability state is principally controlled by: a) polar components in the crude oil such as asphaltene and resin,

b) nature of the rock (mineralogy), c) chemistry of the brine, d) core treatment/preparation and e) aging time.

Polar components in the crude oil- Experiments have shown that the polar components from the crude oil can be adsorbed

by the core surfaces bringing about oil-wet conditions. Several researchers have reported contact angle measurements

indicating that carbonate reservoirs are usually more oil wet than reservoirs with silica (Chilingar et al., 1983; Treiber et al.,

1972).

Mineralogy- Carbonates reservoirs such as dolomite, limestone or chalk (Lucia, 2007; Puntevold et al., 2007) generally

include traces of sulphate in the rock. The presence of sulphate in the rock would have an influence on the initial state of

wettability of the rock (Shariatpanahi et al, 2010) making the rock more water-wet.

Fe

Fe

FeFe

Ca

Si

Ca

Ca

C

Mg

O

Ca

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

keVFullScale2526cts Cursor:0.000

1-2

Mg

Ca

Si

Ca

Ca

C

O

Ca

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

keVFullScale11382cts Cursor:9.905(17 cts)

3-3



SPE-171120-MS 5

Core treatment- Several researchers have published techniques for generating different initial wettability conditions in the

laboratory. A large range of combinations of solvents have been proposed to restore the reservoir conditions. For instance,

Puntevold (2007) reported that special care should be taken with the preparation of carbonate cores. The carbonate cores

cleaned with kerosene and heptanes tend to be preferentially water wet but when toluene and methanol were used, the cores

were more oil wet.

Aging- Aging period for cores with crude oil and formation water has extensively been studied due to its importance. It is believed that aging cores can result in wetting conditions that are more representative of reservoir conditions (compared to

using chemicals). A rise in aging time results in decrease in water wetness (Zhou et al., 2000). Moreover, the restoration of

wettability could begin since the start of the crude oil injection into the core and this could occur faster at high temperature

(Al-Mahrooqi et al., 2005).

Moreover, Chilingar and Yen in their extensive wok found (1983) that principally, carbonate reservoirs are more oil-wet and

intermediate wet systems. In our experiments, the cores were cleaned with toluene and methanol and then were aged for 20

days at 92 oC to restore the original wetting conditions.

Experimental Work

During core flood experiments, complex rock/fluid and fluid/fluid interactions take place which are difficult to interpret. In

this work, we begin by evaluating each element of the parameters affecting the experiments, Figure 2. Core, brine and crude

oil were individually analysed. The details of the interactions between reservoir fluids/injected fluids or injected fluids/rock

can vary widely depending on the composition of such elements. For this reason, interactions between theses elements were

meticulously evaluated before and after each experiment. The outcomes of these simple and practical analyses put in

evidence the level of complexity. The complete evaluation of the fluids/rock interactions led to a better picture of such

indications. Then, the next important parameter that had to be considered was to correctly interprete such results. More

detailed information on interactions, spontaneous imbibition and coreflood tests will be provided below.

Figure 2. Variables dictating or affecting original reservoir conditions.

Effects of Fluids/Rock Interactions- One important consideration in the selection of a water composition for EOR in

carbonates reservoirs, is the compatibility between the injection and formation brine. Formation water of carbonates

reservoirs contains high concentrations of calcium and magnesium, even SO 42-, potential determining ions for wettability

changes (Austad et al., 2005-2007; Puntervold et al., 2009; RezaeiDoust et al., 2009; Shariatpanahi et al., 2010; Tweheyo et

al., 2006; Zhang et al., 2007). Seawater, in contact with formation water, may cause damage to the formation; even more, in

contact with the rock surface this damage can also happen. Recently, we (Gachuz et al. 2013) examined brines in contact with

crude oils. The study revealed that the viscosity of the crude oils changed in contact with brine when crude oils/brines were

shaken or simply by static contact. Therefore, an evaluation of the extent of interactions between crude oil and brine was

performed before starting a coreflood experiment.

Rock

Crude Oil

Formation

Water

Injected

Water



6 SPE-171120-MS

a) Formation Water/ Injection Water Interaction- As we know, some salts show an uncommon bahaviour and

become less soluble in water as the temperature increases (Carlberg et al., 1973; Li et al., 1995). Figure 3 presents a

case where seawater was mixed with formation water resulting in salt precipitation (CaSO 4). For our experiments,

we verified the compatibility between formation brine and injected or imbibing brine. There was no precipitation

under different volume fractions neither at 20 oC nor 92 oC. We concluded that the low salinity waters and seawater

would not cause any precipitation in contact with the formation brine.

Figure 3. Salt crystals formation at high temperature.

b) Crude Oil/Injection Water Interaction.- The procedure described by Gachuz et al. (2013) was used at tests

temperature. The crude oil showed changes in its viscosity, density, water content and pH values. For instance, the

crude oil viscosity decreased when it came in contact with the NW brine at dynamic conditions (samples were

shaken) but when the conditions were static, the viscosity increased (up to 68, 377 cp), see Table 5. For this lastcase, the water content is considerably higher in comparison with the original crude oil’s water content. The

analyses of the water also indicated variations of its pH showing more acidic conditions and its effluents also

reported variations of the ions. In addition, the metal and sulphur content analysis revealed that some metals content

were lower for the crude oil contacted by NW brine. Na +, K + and S2- turned out to be more active. It was evident that

crude oil was undergoing alteration in its structure when was put in contact with injection brines. Although this

simple evaluation has not revealed a pattern in the results, we presume that temperature had a large effect on the

interactions between crude oil and brine even when the fluids were in static conditions. Similar observations were

made when LSSW10 brine was in contact with the crude oil at tests temperature. The oil viscosity increased; pH and

oil density dropped and water content increased dramatically. When crude oils and brines were shaken together, a lot

of small droplets of water would form and remain suspended in the crude oil. These droplets would last for some

time but eventually would go back to the state of two separate phases. Nevertheless, some water droplets stayed

suspended in the crude oil (high amount of water). The water was retained by two main mechanisms described by

Fingas and Fieldhouse (2012): 1) chemically by asphaltenes and resins and 2) by viscous retention of water droplets.The phenomenon of ions exchange between the crude oil and brines is not completely clear, however, on the basis of

these analyses; the crude oil/brine interactions have a large effect even no movement of the fluids.

Table 5. Oil viscosity values for crude oil “A” in contact with two brines.

System

Oil Viscosity

(cp)

Viscosity

Reduction

(%)

Oil Density

(o

API) pH

Water Content

(ppm)

Crude oil A 53,484.31 - 14.12 - 208.40

Crude oil A/NW* 36,314.00 32.10 12.36 6.6 10,795.10

Crude oil A/NW** 68,377.13 - 11.81 4.7 1,151.57

Crude oil A/LSSW10* 66,660.54 - 11.76 3.7 51,218.2*Shaking.**Static condition.



SPE-171120-MS 7

c) Injected Water/ Rock Interaction.-The process of solid precipitation is not limited to water/water interactions; it

can also be caused by incompatibility between injected water and rock mineralogy. The precipitation may reduce the

permeability considerably; therefore, injectivity may be reduced. Before running an experiment, cores were first

fully saturated with formation brine. Then the brine permeability was obtained. Later, the cores were cleaned with

toluene and methanol and then once again they were saturated with either seawater or low salinity brine and

permeability was measured. In general, there were no changes in the cores permeability. The variations were not

significant. The results determined that mixing seawater and low salinity brines would not cause any major damageto the rock. The effluents samples were analised for all ions and some results are present in the Figures 4 and 5. The

solid lines are the original concentrations in the prepared brine.

Figure 4. Variations of potential determining ions at laboratory conditions.

Figure 5. Variations of secondary ions at laboratory conditions.

For limestones cores, samples from effluent were taken when the core was saturated with formation water. The

analyses of the effluents revealed that some ions were released such as sulphur and also small amounts of chloride

and sodium. The Ca2+ decreased its concentration in the brine. In addition, Al 3+ and Fe3+ ions were also present in

the effluent. Although the mineralogy analyses did not show presence of ions cited before, effluent water samples

collected and analysed mainly detected that the concentrations exceed the original values in the original water; this

indicated that the source of these ions was dissolution or release from the rock surface. Later, it was confirmed that

all the limestone cores had traces of anhydrite. For the dolomite cores, they turned out to be more active with

potassium and chloride; even these elements were not present in the mineralogy evaluation. The concentration levels

for sulphur and magnesium sometimes stayed constant. Sulphur or magnesium did not show a pattern, for instance, a





SPE-171120-MS 9

Results and Discussions

SI Experiments

Five SI tests were performed. The results are shown in Figure 6. Limestones core surrounded by brines showed rises of

15.38, 16.47 and 15.31 %. In general, these cores indicated the same oil recovery roughly. It seems to be that the highest

permeability cores yielded the fastest recovery at early time. The experiment with lower permeability core was stopped due tounexpected problems but oil was still slowly produced from the core at that point so we could have expected additional oil

volume. It was of great interest to check the impact of smart fluids against other possible carbonate cores. The fourth and

fifth experiments were conducted using dolomites cores. Seawater was used as smart water (imbibing fluid). The fourth

experiment recovered around 14 % of OOIP, however, the oil recovery was lower than that obtained from the fifth

experiment. This core recovered around 30 %. It seemed that the oil recovery was governed by the permeability when the

dolomite rock was used, hovewer, in the case of limestones the trend was different. The best oil recovery was observed at the

highest permeabilities and not at the lowest values.

When the limestones and dolomites cases for almost the same dimensions are compared, it was observed that faster

recoveries were obtained with dolomite samples. For limestone cores, the process of imbibition took more time than

expected. It is evident that oil production at early stages is better. Figure 7 ilustrates the picture of the imbibition experiments

with both types of rock. The upper faces of the cores revealed accumulation of oil in larger drops, as well as that oil was

expelled from the sides of the cores. In general, the oil drops covered the whole core except for the areas where the surface

was more compact.

Figure 6. Effect of seawater as smart water on spontaneous imbibiton test with different cores at high temperature.

The cores showed a favourable response to seawater and the recovery difference between limestone and dolomite samples

can be attributed to their structures and heterogeneities. It was also conducted an additional imbibition experiment (limestone

core) by directly using NW removing from the brine the active ions, especially sulphate and magnesium. After 15 days, its

recovery was 16.5 % which is slightly higher that the oil recovery by seawater in limestones.

0

5

10

15

20

25

30

35

40

0 5 10 15 20 25 30 35 40 45 50

O i l R e

c o v e r y ( % )

Time (Days)

Spontaneous Imbibition Experiments

92 oC

Limestone 1 (6 mD) Limestone 2 (19.51 mD) Limestone 3 (51.80 mD) Dolomite 1 (194.32 mD) Dolomite 2(345 mD)



10 SPE-171120-MS

Figure 7. Cores producing oil in contact with seawater. Limestone core (left side) and dolomite core (right side).

To monitor a possible interchange of ions during the SI tests, samples of the brines were collected and analysed before and

after the contact with the cores. Original composition and composition at the end of the tests for limestones cores are

presented in Figure 8. Some ions suffered variations such as calcium, sulphur, chloride and sodium. For the experiments

using seawater as smart fluid, the variation of the concentrations was unremarkable for magnesium and chloride, except the

calcium where a rise was more notorious. These variations may be related to the imbibing fluid/rock interaction. The analysis

also reported small variations of sulphur and sodium. Previously, in the effects of fluid/rock interactions section, a rise of the

sulphur during the saturation with formation water was detected and turned out to be important for the anhydrite detection.

This firstly meant that there possibly was dissolution of the rock, removing with the water saturation part of the rock

components. Now, the concentration profile has also changed but in a different scenario for the sulphur at least with seawater

as an imbibing fluid, which could be viewed as almost contradictory. Previous experiments (Austad et al., 2005-2007; Fathi

et al., 2011; RezaeiDoust et al., 2009; Tweheyo et al., 2006) have indicated that the sulphur, calcium and magnesium have

been more active at high temperatures. Those systematic observations have allowed us to confirm that the cores released

additional amounts of calcium but the sulphur remained more reactive with the cores at 92 oC. When NW was used as an

imbibing fluid, small concentrations of sulphur were detected for the imbibing fluid after the imbibition process.

Figure 8. Changes in concentrations of ions when two different waters were used through limestone cores.

As a part of the project of research, a new spontaneous imbibition cell was manufactured in-house to facilitate more

experiments. The objectives of this whole setup are to measure, collect, monitor and record the oil production by spontaneous

imbibition tests from a core at reservoir conditions (up to 200 oC and 10,000 psi). A new series of experiments are being

developed using this setup in order to validate and observe changes concerning pressure, temperature and different imbibing

fluids. The results and more details of this new apparatus will be published soon.



SPE-171120-MS 11

Coreflood Tests

Four tests were carried out. In all of them when the oil production stopped, a change of the injection rate was applied to make

sure that there was no more mobile oil. The oil volume (expressed as a percentage of the original oil in place) was measured

as a function of pore volume injected. The experiments confirmed additional oil recovery when smarts fluids were injected in

both secondary and tertiary mode. Each test had an additional coreflood experiment in order to evaluate repeatability of the

results. They were consistent with the first estimations.

First Coreflood Experiment.-In the first injection cycle, the core was flooded with seawater. In this case, the total amount

of oil was 37.65 % OOIP (Figure 9). The effluents were completely analysed for calcium, magnesium, sulphur, chloride,

sodium, and potassium and possible traces of strontium, iron, silicon and aluminium. The results exhibited that the

concentration of Ca2+ increased whilst the Mg2+ and S2- dropped in the effluents. Chloride, potassium and sodium remained

stable. Minimum traces of others ions were not relevant. These outcomes are in line with studies in SI tests. The recovery

factor with normal brine was lower. 1.83 % of oil was recovered under this method. It appeared that the core was not affected

anymore by normal brine. We analysed the impact of the oil recovery based on the pH and the variation of the effluents.

Nevertheless, the pH did not show a perceptible change. In general, the calcium remained stable in its rise during the whole

experiment. Both effluents and pH for the tertiary program were not analysed.

Second Coreflood Experiment.-For the second coreflood experiment, synthetic seawater first was also injected as a

secondary process and low salinity seawater for a tertiary process. The total recovery factor was 52.09 %, 36.81 % using

seawater and 15.28 % with LSSW10. It appeared that LSSW10 worked much better in comparison with NW for the first

coreflood experiment. The pH of the effluent also was measured at regular intervals after the effluents were collected. The

values are indicated in the Figure 9. The pH values stayed constant during the rest of the injection with seawater. It is also

interesting to observe that for the tertiary program, the pH values increased gradually up to 7.4. The increase of oil recovery

by LSSW can not be attributed to this perceptible change in pH.

The concentration profiles of S2-, Mg2+ and Ca2+in the effluent suffered variations. For instance, S2-and Mg2+ decreased its

concentrations a little, however, there was a constant production of Ca 2+ during all the experimental seawater injection, see

Figure 10. Mg2+ and S2- decreased as Ca2+ increased. The broken lines are the ions analysed from the effluent. This result is

consistent with previous coreflood test (first experiment) where the same ions had similar trends. Zhang et al. reported (2007)

an increase in the effluent calcium concentration during seawater experiment at high temperatures. This reaction was

interpreted as a result of substitution of certain ions on the internal rock surface. In such a case, our results may confirm this

kind of substitution of ions as well. When the cores were saturated with FW at 20 oC, sulphur was gained and calcium was

retained, see Figure 4. Either injecting or imbibing SW at high temperature, the influence becomes more pronounced (Figures8 and 10) and this represents one explanation to the effect attributed to the reactivity of key ions that have the capability of

improving oil recovery. Therefore, S2-, Mg2+and Ca2+ turned out to be more reactive with cores at high temperature.

Figure 9. Oil Recovery and pH versus pore volumes of injected fluids during both secondary and tertiary programs.



12 SPE-171120-MS

Figure 10. Changes in concentrations of ions when flooding seawater through the limestone core 6 at 92oC.

For the second part of the experiment, the behaviour of the concentrations changed (tertiary injection). The ions

concentrations in the beginning of the LSSW injection were higher than injected and this meant that effluents of the first pore

volumes appeared to have a mix of brines, seawater and low salinity seawater. Later, calcium and sulphur was slightly higher

than injected concentrations (Figure 11), in contrast, the magnesium, chloride and sodium concentrations stayed constant.

The potassium was without changes throughout the whole experiment. As we have described; during the course of the

injection pH was monitored in the effluents. In this experiment a pH increase occurred for the tertiary process.

Figure 11. Changes in concentrations of ions when flooding low salinity seawater through the limestone core 6 at 92oC.

Third Corflood Experiment.-Another coreflood experiment was conducted at 92 oC reusing the previous core. For this

experiment, a diluted version of seawater was also flooded as a secondary process. The LSSW injection resulted in the final

recovery of 62.91 % OOIP. After the LSSW10 injection, seawater was injected but did not result in significant production,

Figure 12. Once again, the pH had variations for both processes. On the one hand, the pH increased from ~7.2 to ~7.7 for the

first period. Oil was not observed when the injection rate was increased. After switching to seawater, pH kept about 7.6 due

to the difference in the concentration of ions between LSSW10 and SW. No extra oil was recovered after SW injection. In

both experiments with the same core, the response in the growth in pH during the secondary processes may be caused by the

reaction between the rock and the composition of the injected brine. Effluents were collected for ion analysis. The

equilibrium was assumed to be reached when the effluents pH and ionic composition got at least 5 pore volumes. When no

more oil was produced by LSSW injection, pH stabilised whereas ions concentrations had curious variations composed of

irregular increases and decreases.

Flooding the core with low salinity seawater concentrations of the potential determining ions indicated possibly liberation of

such ions. Figure 13 depicts results where certain ions suffered variations in the concentrations with the same core injecting

low salinity seawater as a secondary process. Magnesium became constant and sulphur became slightly higher that the

original value. Calcium increased at least two more times its concentrations in the effluent. Potassium concentration kept

more or less stable up to 13 pore volumes injected but then made a significant recovery, Figure 13b. The variation continued

for more than 5 pore volumes and could indicate for this case with low salinity seawater that these two ions is being released

by the core and specially the potassium is active for LSSW10 as secondary water. From 13 to 20.6 pore volume injected no

more oil production was gained for this experiment under secondary method, however, important ion changes were detected.



SPE-171120-MS 13

One could generalize that such a variation of ions concentrations in the effluents did not yield extra oil under low salinity

injection. This generalization may be adapted as a working hypothesis for coming experiments.

Figure 12. Cumulative oil recovery at two stages of injection with smart waters.

Figure 13. Variations in ions concentrations during low salinitiy water injection.

Fourth Coreflood Experiment.-In order to validate the outcomings, the third experiment was repetead. The LSSW10

injection was turning out to be as the previous behaviour. During the injection, we had to stop the injection for a while

because of problems with pumps. We had a soak period that lasted 24 hours approximately (at 13.5 injected pore volume).

Later, the injection continued. Unexpected volume of oil was recovered during this time. This event is more clearly illustred

in Figure 14. We did not expect to get this change. This close could have created a new oil bank. Oil production increased

from 61.72 to 67.98 % of OOIP. A rise of the rate was applied to make sure that there was more mobile oil. A new close was

applied in order to validate the new findings. No extra oil was recovered. The pH of the LSSW10 started around 7 and

increased gradually to stabilize at approximately 7.8. Effluents were also taken and they were analysed. Based on Middle

East results (Yousef et al., 2010-2011-2012), a second diluted version of seawater was considered for the tertiary program.

This new version had 50 times less salt concentrations. It did not result in significant production. Once again, the pH had

variations. On the one hand, the pH increased from ~6.7 to ~7.9. The pH did not increase when we modified the rate of



14 SPE-171120-MS

injection. Oil was not observed during these variations. On the other hand, after switching to LSSW diluted 50 times, some

extra oil was recovered after injection of this new brine, ~1 % of OOIP.

Figure 14. Recovery oil vs pore volume for the fourth experiment.

Figure 15. Presence of more ion concentrations in effluents for limestone 6.



SPE-171120-MS 15

Figures 15 describe the variations in ions concentrations for this experiment. For magnesium and sulphur, no major variations

on the concentrations occurred. Calcium rose at 2 times the original concentration and then maintained stable at those values.

It may be seen that potassium rose from 5 to 20 pore volume injected then dropped off and reached low values. The core

exposed to LSSW50 injection did indicate loss of potassium from the brine at the same time an amount of calcium was

produced by the core, Figure 16.

Figure 16.Chemical analysis results for Ca2+ and K+ in effluents for limestone6 flooded with LSSW50.

Remarks

Three experiments performed at 92 oC using the same core, confirmed additional oil recovery when low salinity water was

injected in both secondary and tertiary modes, Figure 17. An additional recovery of 15.28 % was obtained when low salinity

seawater was injected after seawater. pH and specific ions (calcium and potassium) concentration were higher than the

original values during secondary LSSW injection. A summary of the results is presented in the Table 7.

Figure 17. Final recovery factors for the limestone 6 with different scenarios of injection.



16 SPE-171120-MS

Table 7. Results for smart water injection program in the limestone core 6.

Process Fluid First

Experiment Fluid

Second

Experiment Fluid

Third

Experiment

Secondary Process Seawater 36.81 % Low Salinity

Seawater 62.91 %

Low Salinity

Seawater67.98 %

Tertiary Process

Low Salinity

Seawater 15.28 % Seawater 0.74 %

Low Salinity

Seawater (50) 1.10 %

The most significant observations from this work are that injection of diluted seawater into carbonate rocks brought about

significant additional oil recovery up to 65 % of OOIP in secondary mode. This result clearly demonstrates the substantial

potential of a properly designed low salinity seawater and seawater injection in recovering significant additional oil from

heavy oil carbonate reservoirs. This result is significant as it indicates that low salinity water injection can potentially be a

lower cost alternative for other oil recovery processes used for heavy oil recovery such as thermal methods, gas injection or

variations of them (Adibhatla et al., 2006; Gupta et al., 2007-2009; Han et al., 2011; Weiss et al., 2007).

Conclusions

The explotation of heavy and extra-heavy oil resources has so far been minimal and more work still need to be done. Our

goal in this work is to motivate further research into exploring potentials of smart water injection for as a cost effective

alternative oil recovery technique for heavy and extra-heavy oil recovery. The following conclusions can be drawn from this

study:

Smart water injection has so far been mainly considered for light oil reservoirs, but our results reveal that it may also

have significant potential for improving recovery from extra-heavy and heavy oil carbonate reservoirs.

The results of the experiments performed in this work with smart water have demonstrated that substantial

additional amount of oil can be obtained under secondary as well as tertiary injection.

An important observation to be highlighted is the additional oil recovery reported from a soak period which

represented around 8 %. The shut-in period led to bigger contact time between the injected fluid and the core

allowing the water to act through unswept zones for longer time expelling oil from the rock matrix into the channels.

Fluid analysis showed changes occurred in the concentrations of certain ions which caused a possible change of

wettability producing more oil.

Rock/fluids interaction evaluations revealed that there was no a direct relationship between pH increase and

additional recovery as it had been pointed out for low salinity water injection. For carbonate rocks, an increase of pH

is originated by the brine/rock interaction not by brine/rock/oil interaction.

Acknowledgements

The authors acknowledge the financial support for this project provided by the National Council for Science and Technology

and the Ministry of Energy of Mexico (Conacyt-SENER-Hidrocarburos). Acknowledgement is extended to Lorraine Boak

and Wendy Mcewan for their support and help with ICP analysis. Special thanks to Amir Farzaneh for helpful discussions.



SPE-171120-MS 17

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SPE-171120 Smart Water Injection for Heavy Oil Recovery from Naturally Fractured Reservoirs