SPE 141082

Smart WaterFlooding for Carbonate Reservoirs: Salinity and Role of Ions Ali A. Yousef, Salah Al-Saleh, and Mohammed Al-Jawfi, Saudi Aramco

Copyright 2011, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Middle East Oil and Gas Show and Conference held in Manama, Bahrain, 25–28 September 2011. 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 salinity level of injection water in the past has not been considered as a key parameter in oil recovery from water-flooded

reservoirs. In the recent years, extensive research on oil/brine/rock systems has shown that injection low salinity brines has a

significant impact on the amount of oil recovered. Although, the potential for carbonates has not been thoroughly investigated,

some reported studies have excluded carbonates from this effect.

Saudi Aramco through its upstream research arm (the Advanced Research Center) has initiated a strategic research program

tagged “Smart WaterFlood” to explore the potential of increasing oil recovery by tuning the injection water properties. Based on

the research work for the last three years, we demonstrated in a previous report (SPE 137634) that substantial oil recovery beyond

conventional waterflooding from carbonates can be achieved by optimizing the salinity and ionic composition of field injection

brine. Also, research confirmed that the driving mechanism is wettability alteration of carbonate rock surface.

This paper highlights extensive and a broad range of laboratory studies including wettability and surface chemistry studies to

define the role of water ions in the induced wettability alteration, which is crucial in determining the optimum composition of

injection water for future field applications.

The rock surface chemistry studies pointed out the potential mechanisms for wettability alteration triggered by injecting

different salinity slugs of field injection water. The contact angle results indicated that a sufficient reduction in the ionic strength of

field injection water is required to trigger the effect of wettability alteration. All evidence gathered during this research work

indicate that what we deal with in this study is a new research trend, different from what have been addressed in the literature on

low salinity waterflooding for sandstones, and seawater injection in chalks.

Introduction

Waterflooding by all measures has been the most successful method for recovering oil from reservoirs. The key ground for the

success of waterflooding include a) Water is an efficient injectant for displacing oil of light to medium gravity, b) Water is

relatively easy to inject into oil-bearing formations, c) Water is available and most importantly inexpensive, and d) Waterflooding

involves much lower capital investment and operating costs, leading to favorable economics compared to the EOR methods.

The target of any waterflood reservoir management is primarily to maximize the ultimate oil recovery. The attention has been

given historically to improve the volumetric sweep efficiency through a number of technologies and practices including in-fill

drilling, multilateral wells, improved reservoir characterization, high resolution reservoir simulation, advanced monitoring and

surveillance, and many others. Because waterflooding has been viewed as a physical process to maintain reservoir pressure and

drive oil towards the producing wells, less attention has been given to the role of the chemistry of the injection water and its impact

on oil recovery. In recent years, extensive research has shown that tuning salinity and ionic composition of the injected water can

favorably affect oil/brine/rock interactions, enhance microscopic displacement efficiency, and eventually improve waterflood oil

2 SPE 141082

recovery. One emerged trend targeting sandstone reservoirs has shown that injecting low salinity water can significantly improve

oil recovery.

Tuning the salinity and ionic composition of the injection water is relatively new and currently in the R&D stage. There have

been a few field trials, all in sandstones. The initial results are promising, and while many recovery mechanisms are proposed, still

many questions and uncertainties remain with respect to the oil recovery mechanisms and the role of the injection water chemistry.

The potential for carbonate reservoirs has not been thoroughly investigated and some of reported studies have excluded carbonates

from this effect (Lager et al., 2006; Doust et al., 2009).

Saudi Aramco, through its upstream research center (EXPEC ARC), has initiated a strategic research program tagged “Smart

WaterFlood” to explore the potential of increasing oil recovery from carbonate reservoirs by tuning properties of the injection

water (e.g., salinity, ionic composition, interfacial tension, viscosity, and others). Several Saudi Aramco reservoirs have natural

water drives that have been augmented by peripheral water injection programs since the mid 1950s. The produced water is re-

injected. A string of development of the injection system has been implemented over the past 60 years. This has resulted in unique

water injection infrastructure, considered today the largest in the world. Currently, the primary source of the injection water is

seawater. The potential of obtaining incremental oil recovery through tuning the injected water properties is significant considering

the current injection water facilities as well as the large oil resources of the Kingdom.

Based on the research work for the last three years, we presented in a previous report (Yousef et al., 2010) a new recovery

method/process for carbonate reservoirs labeled “Smart WaterFlooding” to improve or enhance oil recovery through altering the

salinity and ionic composition of injection seawater. This was demonstrated through different well tailored coreflooding

experiments using composite cores from one of Saudi carbonate reservoirs. The experimental parameters and procedures were well

designed to reflect reservoir conditions and current field injection practices, including reservoir pressure, reservoir temperature,

initial reservoir connate water (Salinity of 200 kppm), and synthetic brines of injection seawater. The method consists of a

sequential injection of various diluted versions of regular seawater. Different practices were implemented to ensure ahead of

injection any tertiary slug that the residual oil is attained through specific injection practices. The additional oil recovery was ~7%

- 8.5% with twice diluted seawater; ~ 9% - 10% with 10 times diluted seawater, and ~ 1% - 1.6% with 20 times diluted seawater,

all in terms of the original oil in cores (OOIC).

A comprehensive recovery mechanism study was also presented (Yousef et al., 2010) to address the main mechanisms for

substantial increase in oil recovery observed in reported coreflood experiments. The main research findings include:

The recovery mechanism study confirmed that wettability alteration is the main cause for substantial increase in oil

recovery observed in reported coreflood experiments. The significant alteration was observed with twice diluted seawater

and also 10 times diluted seawater.

The recovery mechanism study also demonstrated that Smart WaterFlooding has irrelevant impact on IFT measurements,

compared to contact angle measurements; this implies that diluting seawater mainly affect fluid-rock interactions.

NMR measurements for all rock samples used in coreflood experiments, prior and post Smart WaterFlooding, indicated

that injecting different salinity slugs of seawater in carbonate core samples causes a significant alteration in the rock

surface charges.

This paper provides first a literature review on the impact of the injection water chemistry on rock wettability, and then

presents a broad range of laboratory studies to confirm potential mechanisms for wettability alteration using different salinity slugs

of injection seawater, and also to address the effect of seawater ionic strength on the induced wettability alteration.

Review on the Impact of the Injection Water Chemistry on Rock Wettability and Oil Recovery

Wettability alteration has been always proposed as the driving mechanism for improved oil recovery by altering the salinity and

ionic composition of the injected water. During waterflooding, different forces control fluid flow in porous media including

viscous, capillary and gravity forces. Capillary forces are the most dominant at the end of the waterflooding, and create what we

refer to as the residual oil saturation. To mobilize the residual oil, a significant reduction in capillary forces is required. Capillary

forces are a function of fluid-fluid, and fluid-rock interactions. IFT measurements between oil and water, and rock wettability

measurements (i.e., contact angle) are typically used to measure these interactions.

Rock wettability alteration by tuning the salinity and ionic composition of the injection water has been addressed since the

1960s. Bernard (1967) demonstrated that injection of fresh water both in secondary and tertiary modes can increase oil recovery

SPE 141082 3

from sandstone cores containing clays. The research work of Jadhunandan (1990) pointed out one more time that injecting low

salinity water into sandstone core samples can affect oil recovery. Extensive research works (Jadhunandan and Morrow, 1995;

Yildiz and Morrow 1996; Tang and Morrow 1997; Tang and Morrow 1999; Tang and Morrow 2002; Zhang and Morrow 2006;

Zhang et al., 2007) have developed this idea into an emerged trend. The research efforts of Webb et al., (2005a), Lager et al.,

(2006), and Lager et al., (2007) have confirmed and validated the new trend through reservoir conditions coreflood experiments.

Lager et al., (2007) reported that the average increase in oil recovery from more than 20 reservoir coreflood experiments was

around 14%. The laboratory results were confirmed by field tests including log-inject-log and different single well chemical tracer

tests (Webb et al., 2004; MaGuire et al., 2005; Lager et al., 2008).

The efforts in the past two decades have been devoted to understand recovery mechanisms of low salinity waterflooding.

Although different mechanisms have been proposed, many questions and uncertainties remain. However, it is well documented

that the effect of low salinity is related to the presence of clay minerals (Tang and Morrow 1996; Lager et al., 2006), and

accordingly, it is generally accepted that the effect is caused by wettability alteration of clay minerals. The main mechanisms

proposed for wettability alteration include fine migration (Tang and Morrow 1999), pH increase leading to interfacial tension (IFT)

reduction (McGuire et al., 2005), multi-ion exchange (Lager et al., 2006), and double layer expansion (Ligthelm et al., 2009; Doust

et al., 2009). Lager et al., (2006) showed that a pH increase and fine migration are symptoms of low salinity effect rather than

potential mechanisms. Most recently, Berg et al., (2009) provided direct experimental evidence indicating multi-ion change and/or

double layer expansions are the potential mechanisms for low salinity waterflooding. Based on what have been published so far in

the literature, the mechanisms are mainly linked to the presence of clay minerals, oil composition, the presence of formation water

with high concentration of divalent cations (i.e., Ca2+, Mg2+), and the salinity level of the low salinity water in the range of 1,000

ppm - 5,000 ppm.

Another research work targeting chalk reservoirs indicated that injecting seawater rather than any other types of water will

improve oil recovery (Austad et al., 2005; Strand et al., 2006; Zhang and Austad 2006; Zhang et al., 2007; Austad et al., 2008).

This effect is attributed to the reactivity of key seawater ions (SO42-, Ca2+, Mg2+) that have the capability to change rock surface

charges, release adsorbed carboxylic oil component from rock surface, alter rock wettability, and eventually improve oil recovery.

Webb et al., (2005b) investigated the impact of the sulfate ion on imbibition capillary pressure curve, and saturation changes using

two identical chalk cores. Sulfate-free formation water was used as initial water saturation in both cores, and seawater and sulfate-

free formation water were used as imbibing fluids. The results showed that seawater was able to alter the wettability of the chalk

core sample to more water-wet state. This trend has so far been demonstrated through spontaneous imbibition tests in which

spontaneous imbibition oil recovery showed a significant dependence on temperature; the higher the temperature, the higher the oil

recovery. The conditions necessary to trigger this effect based on reported studies include oil with high polar components, sulfate-

free formation water, temperature > 90 °C, and high concentration of key seawater ions in the injected water.

Based on published research work (Austad et al., 2005; Strand et al., 2006; Zhang and Austad, 2006; Zhang et al., 2007;

Austad et al., 2008), different mechanisms for wettability alteration have been proposed, including surface charges alteration by

adsorption of SO42- with co-adsorption of Ca2+ on chalk rock surface, and substitution of Ca2+ on chalk rock surface by Mg2+

because of increasing in ion reactivity at higher temperature. During imbibing seawater into a chalk rock sample, it is proposed

that sulfate ion (SO42-) will adsorb on a positively charged chalk surface, consequently, the bond between a negative oil component

and rock surface will deteriorate. Due to a decrease in the positive surface charge, more Ca2+ ions will be able to attach to the rock

surface allowing releasing negative oil component. As temperature increases, this effect becomes more pronounced and this

represents one explanation to the correlation between oil recovery and temperature observed in spontaneous imbibition tests

(Strand et al., 2006). Also, it is proposed that at higher temperatures, these ions become more reactive with the chalk rock surface,

and this will induce the substation of Ca2+ on rock surface by Mg2+.

A recent research work has called into question the proposed surface charge alteration mechanism, as described earlier. Hiorth

et al., (2010) investigated how water chemistry affects surface charge and rock dissolution in a pure calcium carbonate rock by

constructing and applying a chemical model that couples bulk aqueous and surface chemistry and also addresses mineral

precipitation and dissolution. The developed chemical model was used to predict temperature dependence of oil recovery reported

in spontaneous imbibition experiments (Zhang and Austad 2006; Zhang et al., 2007; Austad et al., 2008). The results indicated that

the surface charge alteration cannot explain the observed increase in spontaneous oil recovery caused by seawater imbibition

and/or temperature. Because the precipitation/dissolution model was able to predict temperature dependence of oil recovery with

imbibing fluids, mineral dissolution was proposed as a controlling factor in the reported spontaneous imbibition data.

4 SPE 141082

Experimental Studies

Rock Samples Selection and Preparation

The rock material was selected from a carbonate reservoir. Core plugs (1-in. in diameter, and 1.5-in. in length) were cut from

whole cores. Different laboratory tests were exercised to select a consistent rock samples in terms of petrophysical properties as

well as rock types; this includes routine core analysis, X-ray Computerized Tomography (CT) scan, and nuclear magnetic

resonance (NMR) T2 distribution. Routine core analysis was first conducted to measure the dimensions, air permeability, porosity,

and pore volume of core plugs. The core plugs were then CT scanned to screen out any core with fractures or permeability barriers.

Afterwards, saturation cores were NMR analyzed to sort core samples into groups with different petrophysical properties. Table 1

lists the petrophysical properties of the selected cores for this study.

Fluid Properties

Brines

Different brines were used in this study, including field connate water, injection seawater, different salinity slugs of injection

seawater, and optimized ionic composition of field seawater. All brines were prepared from distilled water and reagent grade

chemicals, based on geochemical analysis of field water samples. For experimental work described below, seawater had a salinity

of about 57,600 ppm, and initial connate water is very saline with salinity of 213,000 ppm by weight.

The salinity of the injection seawater is almost double the typical salinity of ocean seawater. Other dilute versions of seawater

were also prepared by mixing with different volumes of de-ionized water including twice dilutes (~29 kppm), 10 times dilutes (~6

kppm), 20 times dilutes (~3 kppm), and 100 times dilutes (~0.6 kppm).

A new set of brines was also prepared to investigate the effect of ionic strength of field seawater on wettability alteration. This

includes twice diluted ionic strength, 10 times diluted ionic strength, 20 times diluted ionic strength, and also 100 times diluted

ionic strength.

Reservoir Oil Samples

Reservoir oil samples were used in this study. Crude oil filtration was conducted to remove solids and contaminants to reduce any

experimental difficulties during coreflood experiments. In this work, live oil was used in which it was recombined from a separator

of oil and gas such that the experimental conditions closely resembled reservoir conditions.

Surface Chemistry Study

We investigated the impact of each diluted version of seawater on carbonate rock samples using coreflooding and NMR

instruments. The objective of this study is to confirm that injecting diluted seawater can cause a significant alteration in the surface

charges of the carbonate rock leading to wettability alteration, and also to determine the role of each salinity slug in the observed

trend.

Coreflooding Apparatus

Coreflooding apparatus used in this work is custom designed to perform experiments with single or composite core plugs to

evaluate oil recovery using waterflooding. Figure 1 shows an image of the experimental equipment. The main components of the

apparatus are oven, stainless steel core holder, fluid accumulators, differential pressure array, one Quizix pumps, back pressure

regulator (BPR), confining pressure module, and fractional collector. The flooding system is capable of handing temperature up to

150 °C, pore pressure up to 9,500 psi, and overburden pressures up to 10,000 psi. Volumes of oil and different salinity brines are

supplied from high-pressure floating piston accumulators, operated by external high-pressure pumps. Oil and brine injection was

accomplished through a Quizix pump connected by a set of valves ahead of the core holder. System pressure is maintained by a

back pressure regulator (BPR) at the core outlet, and measured by absolute and differential pressure transducers. The coreflooding

apparatus is equipped with a fractional collector used to collect production fluids.

Laboratory NMR Technique and Instrument

NMR has emerged as a rapid, nondestructive, and noninvasive measurement technique for both laboratory and field applications.

There have been considerable efforts made in the last few decades to understand the NMR properties of fluids in porous medium.

It has been documented that a number of rock properties of practical interest are correlated with NMR amplitude and relaxation

times (Borgia et al., 1991; Kenyon 1992; Howard 1998; Bryar and Knight 2003). These include pore size distribution, porosity,

permeability, rock wettability, hydraulic permeability, pore fluids identification, and others. As a result of those laboratory studies,

novel bench-type NMR instruments have been designed to measure/infer petrophysical properties for reservoir rock samples.

SPE 141082 5

The principle of a NMR technique is that the protons in fluids contained in medium like rock samples or formations, are

randomly oriented. When a natural or artificial static magnetic field and one or more pulses with adjusted frequencies are applied,

the spin axes of protons will be aligned in a particular direction. Fluctuation of the magnetic field will tip these protons away from

their new equilibrium position, and when the magnetic field is subsequently removed, the protons begin relaxing, toward the

original direction; and this relaxation signal (NMR single) is measured and decomposed into its constituting components and

displayed as a NMR surface relaxation or T2 distribution. This distribution is the basis for further petrophysical interpretation, and

one of well established laboratory NMR applications is to infer rock pore size distribution directly from NMR surface relaxation,

T2, (Straley et al., 1997).

In general, the T2 relaxation rate of a fluid sample in a porous rock can be described as (Kenyon 1992):

…………………………………………………………………………………… (1)

where T-12B is the relaxation rate of the bulk water, S/V is the surface area to the volume ratio of the pores, and ρ is the transverse

surface relaxivity. Surface relaxivity (ρ) is a geochemical property describing the capacity of the grain surface to enhance

relaxation and generally increases with the concentration of paramagnetic impurities on a surface (e.g., Mn2+, Fe3+) (Foley et al.,

1996; Bryar et al., 2000). The product ρ (S/V) is referred to as the surface relaxation rate, and reflects the effect of both pore

geometry and geochemistry or water chemistry on pore surface. The third term describes the T2 relaxation rate due to diffusion in a

magnetic field gradient (Callaghan 1991). D is the molecular self-diffusion of the water, G is the magnetic field gradient, γ is the

gyromagentic ratio of the hydrogen nucleus, and τe is the echo time, a constant parameter for the measurement. Relaxation in rock

samples with negligible magnetic susceptibility is dominated by surface relaxation or is assumed to be in the fast-diffusion regime

in which case the expression for T-12 is simplified to:

……………………………………………………………………………………………. (2)

This equation holds for isolated pore systems and is a widely-used approximation for systems with well connected pores in

NMR logging applications. In porous rocks, the rock grains usually vary in size, and have different pore systems which lead to an

effective distribution of pore sizes and, accordingly, a distribution of relaxation times.

The NMR system used is the Maran DRX 2 MHz (Fig. 2). The system has a 2 MHz permanent magnet with a three

dimensional water cooled 15 Gauss/cm electromagnetic gradient coils for imaging. NMR T2 distributions were determined using a

BDR inversion scheme in which the amplitude of the decay signal can be fit by a sum of decaying exponentials and the set of all

the decay constants forms T2 distribution

Experimental Procedure

The measurements were conducted using carbonate core plugs and different salinity slugs of injection seawater. The measurements

were conducted in a sequential mode.

Wettability Measurements at Reservoir Conditions

Contact angle is considered one of the most common methods to quantify rock wettability. It was used in this study to address the

role of seawater ions in the induced wettability alteration reported in previous study (Yousef et al., 2010). The general

conventional classification of contact angle is (Anderson 1986): water-wet, 0°~75°; intermediate-wet, 75°~115°; and oil-wet,

115°~180°.

Contact Angle Apparatus

The pendent drop instrument, Fig. 3, was used to measure the contact angle of carbonate rock samples with live oil and optimized

ionic composition of injection seawater. The main parts of the instrument are the contact angle chamber, the hand pump for

injection of oil or water, a vibration free table, needle, temperature control system, lamp, transfer cells, pressure transducers with

digital display, and a fully automated imaging system. The imaging system allows a direct digitization of the drop image with the

aid of a video frame grabber of a digital camera. Figure 4 shows a schematic diagram of the contact angle chamber used in this

study.

Experimental Procedure

Two sets of contact angle measurements were carried out using optimized composition of field seawater. The measurements were

conducted in a sequential mode: field connate water, field seawater, twice dilute, 10 times dilute, 20 times dilute, and eventually

100 times dilute of field seawater ionic strength.

eB

GD

V

S

TT

12

11

22

V

S

T

2

1

6 SPE 141082

Beside the procedure used in conducting contact angle measurements, another important step is the selection and cleaning of

rock plate samples. The samples were obtained from tight rock samples characterized by very low permeability (about 2 md-air) to

avoid oil drop imbibition in the rock plate while doing the measurement. Also, rock plates were then washed with distilled water

and ethanol. To restore rock wettability, rock plates were first aged in connate water for 7 days, and then aged in the field oil for

six weeks.

Results and Discussion

Surface Chemistry Study

From previous reported study (Yousef et al., 2010), one major observation from NMR measurements for all rock samples used in

coreflood experiments is the significant shift in the position of T2 distribution between NMR results before and after coreflood

experiments. All rock samples exhibited fast surface relaxation (shorter T2 times) after injecting different salinity slugs of

seawater. One feasible explanation proposed is a significant increase in rock sample surface relaxivity (ρ). Because an increase in

surface relaxivity also reflects an increase in the capacity of pore surface to enhance relaxation of excited protons, this suggests

that diluting seawater can alter surface charges of carbonate rock- one approach of wettability alteration. In this work, we

investigated the impact of each diluted version of seawater on carbonate rock samples using coreflooding apparatus, and NMR

instrument.

The carbonate reservoir, targeted in this study, typically consists of different pore systems including macropores, and different

micropores types (Type 1, 2, 3) (Clerke et al., 2008; Cantrell and Hagerty 2003). NMR response, for water saturated carbonate

rock samples, usually indicates these pore systems at different T2 values. In simple words, small pores or micropores will have

small T2 values and large pores (macropores) will have large T2 values. Figure 5 shows T2 distribution for carbonate rock sample

used in this study saturated by de-ionized water.

NMR T2 distribution results after each slug were generated. This includes de-ionized water, field connate water (~ 213 kppm),

field seawater (~ 57 kppm), twice diluted (~29 kppm), 10 times diluted (~6 kppm), 20 times diluted (~3 kppm), and eventually 100

times diluted seawater (~0.6 kppm). De-ionized water was used in this study to determine T2 distribution of rock sample

independent from water chemistry. Also, this represents the base line for subsequent T2 measurements with other types of water.

One important observation from these results is that there is no observed change in T2 time of de-ionized water after flooding rock

sample by field connate water, and also field seawater, though there is a significant contrast in the salinity and also ionic

composition among these slugs. However, the rock sample exhibited fast surface relaxation (shorter T2 times) after diluted slugs of

seawater. All of these observations are consistent with NMR results conducted before and after coreflood experiments (Yousef et

al., 2010). The new results consequently confirmed that injecting diluted seawater as described in this work is able to cause a

significant alteration in the surface charges of the carbonate rock, lead to more interactions with water molecules, and eventually

alter rock wettability.

Wettability Measurements at Reservoir Conditions

We demonstrated in Yousef et al. (2010) that injecting different salinity slugs of seawater is able to change rock wettability toward

water-wet. To obtain an insight on the effect of ionic strength of field injection water in this induced wettability alteration, contact

angle measurements were conducted using new sets of optimized ionic composition of seawater.

Two tests of contact angle measurements were conducted using connate water, field seawater, and also versions of field

injection water with different ionic strengths. The general trend is that as the ionic strength decreases, the rock wettability shifts

toward the water-wet state. The contact angle with field connate water is ~90°, indicating intermediate wettability of the rock

sample. Field seawater showed slight to significant shift in rock wettability. We observed a significant change in the contact angle

with twice diluted and also 10 times diluted ionic strength of seawater; in both tests, these two slugs showed at least ~10° shift in

the contact angle, and the rock wettability after these two slugs became in the water-wet zone. Less alteration has been observed

with 20 times diluted and 100 times diluted ionic strength of seawater.

The trend of wettability alteration observed in this study is very similar to the trend of wettability alteration observed with

diluting field seawater (Yousef et al., 2010). This confirmed that altering the ionic strength of field seawater is required to induce

wettability alteration in Smart WaterFlooding. Further research is ongoing to address the role of each ion in this observed trend.

SPE 141082 7

Conclusions

We reported on a broad range of laboratory studies to confirm potential mechanisms for a new recovery method/process for

carbonate reservoirs tagged “Smart WaterFlooding”, and also to address the role of seawater ions in the current emerged research

trend. The method consists of a sequential injection of various diluted versions of regular seawater. Different practices were

implemented to ensure ahead of injection any tertiary slug that the residual oil is attained through specific injection practices. The

additional oil recovery was ~7% - 8.5% with twice diluted seawater; ~ 9% - 10% with 10 times diluted seawater, and ~ 1% - 1.6%

with 20 times diluted seawater, all in terms of the original oil in cores (OOIC). The following are the main research findings in this

study:

The recovery mechanism study confirmed that Smart WaterFlooding is able to alter the rock wettability toward a more

water-wet state. The significant alteration was observed with twice diluted seawater and also 10 times diluted seawater

where these two slugs provided substantial additional oil recoveries.

The rock surface chemistry studies using coreflooding and NMR instruments confirmed that injecting different salinity

slugs of seawater in carbonate core samples causes a significant alteration in the surface charges of the rock leading to

more interaction with water molecules. This is the main mechanism for wettability alteration observed in Smart

WaterFlooding.

Extensive contact angle measurements confirmed that a significant reduction in the ionic strength of field seawater is

required to trigger the effect of wettability alteration, and eventually provide additional oil recovery.

All evidence gathered during this research work indicated that Smart WaterFlooding is a new research trend, different

from what has been proposed in the literature on the topics of low salinity waterflooding for sandstone reservoirs, and

injection of seawater in chalk reservoirs. This does not imply that there are no similarities among these research trends;

however, each trend will need a certain condition to trigger its effect in terms of additional oil recovery.

The results, observations, and interpretations addressed over the past three years provided compelling evidence that the

driving mechanism for substantial oil recovery by Smart WaterFlooding is wettability alteration; as indicated by the NMR

results, this can be triggered by mainly alteration of surface charges of carbonate rock.

Acknowledgements

The authors would like to thank the Saudi Arabian Oil Company (Saudi Aramco) for granting permission to present and publish

this paper. The authors would also like to thank the management of EXPEC ARC.

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SPE 141082 9

Table 1. Basic Petrophysical Properties for Rock Samples

Sample # Length

(cm) Dia. (cm)

Air K (mD)

Brine K (mD)

Porosity (%)

Target Study

A 4.31 3.79 59.4 25.36 28.31 Surface Chemistry Study

B 3.88 3.79 388.1 190.41 29.7 Surface Chemistry Study

C 4.00 3.80 2.0 ---- ---- Wettability Study

D 3.93 3.80 4.0 ---- ---- Wettability Study

10 SPE 141082

Fig. 1. Image of the coreflooding apparatus.

Fig. 2. Image of the laboratory NMR system.

Fig. 3. System setup for contact angle measurements at reservoir conditions.

SPE 141082 11

Fig. 4. A schematic diagram for contact-angle chamber.

Fig. 5. NMR T2 distribution for carbonate rock sample after flooding by de-ionized water.

Needle

Rock Plate

Oil Drop

Faster Relaxation

SlowerRelaxation

Macro Pores

System

T2 Max

Different

Micro Pores System