SPE-171120-MS Smart Water Injection for Heavy Oil Recovery from Naturally Fractured Reservoirs Heron Gachuz-Muro, Heriot Watt University/Pemex E&P; Mehran Sohrabi, Heriot Watt University Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Heavy and Extra Heavy Oil Conference - Latin Americaheld in Medellin, Colombia, 24 –26 September 2014. 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 Enhanced Oil Recovery (EOR) from carbonate reservoirs can be a great challenge. Carbonate reservoirs are mostly oil-wet and naturally fractured. For this type of reservoirs, primary production is derived mainly from the high permeability fracture system which means that most of the oil will remain unrecovered in the low permeability matrix blocks after depletion. Further difficulties arise under high pressure and high temperature conditions. Oil recovery from carbonated rocks may be improved by designing the composition and salinity of flood water. The process is sometimes referred to as smart water injection. The improvement of oil recovery by smart water injection is mainly attributed to wettability modification in the presence of certain ions at high temperature. The resultant favourable wettability modification is especially important for naturally fractured reservoirs where the spontaneous imbibition mechanism plays a crucial role in oil recovery. The objective of the work presented here was to experimentally investigate the performance of smart water injection for heavy oil recovery from carbonate rocks under high reservoir temperature. A series of coreflood experiments were performed using a group of carbonate cores in which smart water injection was tested under both secondary and tertiary injection conditions. The experiments were conducted at 92 o C using an extra-heavy oil. Seawater from Gulf of Mexico (GOM) was used in the seawater injection experiments and the smart water used in the tests was obtained by 10 times dilution of the seawater. Although concentration of SO 4 2- is lower in the smart water, the occurrence of SO 4 2- as anhydrite in carbonates may be sufficient to stimulate a similar reaction bet ween the carbonated rock and the injected water with lower salinities at high temperatures. Seawater injection resulted in oil recovery ranging between 30% and 40% whereas smart water injection resulted in 60% oil recovery from the same system. Additionally, analyses of brine composition before and after coreflood experiments confirmed that the effluent concentrations of SO 4 2- , Mg 2+ and Ca 2+ changed compared to its original values in the injected water. The results indicated that, for some cases, the source of these ions was dissolution from the rock surface. The reactivity of the rock increased when lower salinity water was used.
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8/10/2019 SPE-171120 Smart Water Injection for Heavy Oil Recovery from Naturally Fractured Reservoirs
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.
8/10/2019 SPE-171120 Smart Water Injection for Heavy Oil Recovery from Naturally Fractured Reservoirs
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
8/10/2019 SPE-171120 Smart Water Injection for Heavy Oil Recovery from Naturally Fractured Reservoirs
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.
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
8/10/2019 SPE-171120 Smart Water Injection for Heavy Oil Recovery from Naturally Fractured Reservoirs
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.
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.
8/10/2019 SPE-171120 Smart Water Injection for Heavy Oil Recovery from Naturally Fractured Reservoirs
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