Coreflooding Oil Displacements with Low Salinity Brine

Copyright

by

Scott Michael Rivet

2009

ii

Coreflooding Oil Displacements

with Low Salinity Brine

APPROVED BY

_______________________________________ Larry Lake, Advisor

_______________________________________ Gary Pope, Co-advisor

iii



by

Scott Michael Rivet, B.S.

Thesis

Presented to the Faculty of the Graduate School

of The University of Texas

in Partial Fulfillment

of the Requirements

for the Degree of

Master of Science in Engineering

The University of Texas at Austin

December 2009

iv

ACKNOWLEDGMENTS

I would like to express my sincere gratitude toward Dr. Larry Lake

and Dr. Gary Pope for their guidance. You were both very supportive,

helpful and understanding throughout my time here at The University of

Texas. I’ve enjoyed working with you both and wish ya’ll the best.

I would also like to acknowledge the Chemical Enhanced Oil

Recovery Research Project in the Center for Petroleum and Geosystems

Engineering and it’s member sponsors for their financial support. The

Chemical EOR Research Project’s sponsors include, in no particular order,

Hess, Oxy, Pemex, Stepan, Petrobras, Rex Energy, Harcros, ConocoPhillips,

Petronas, Marathon, Huntsman, ExxonMobil, Total, Shell, BP, Chevron,

StatoilHydro, BASF, Schlumberger, SNF, ENI, Cairn and Saudi Aramco.

I would also like to thanks the Department of Petroleum and

Geosystems Engineering, The Friend’s of Alec Fellowship, the Energy and

Mineral Resources Fellowship, the H.B. Burt Harkin’s Jr. Professorship

Endowment Fellowship and the John and Mary Wheeler Endowed Graduate

Fellowship for their financial support.

I am also thankful for the suggestions and assistance of Dr. Steven

Bryant, Dr. Do Hoon Kim, Chris Britton, Yihao “Jarren” Xie, Aigul

Kurmanova, Dr. Larry Britton, Glen Baum, Gary Miscoe, Esther Barrientes,

Kiki Peckhman, Joanna Castillo, Will Slaughter and David Levitt to name a

few.

Lastly, I would like to thanks my parents for their support.

v



by

Scott Michael Rivet, M.S.E.

The University of Texas at Austin, 2009

Supervisors: Larry Lake and Gary Pope

Waterflooding is applied worldwide to improve oil recovery. Evidence of

enhancement in waterflood efficiency by injecting low salinity brine has been

observed in the laboratory and in the field. The technology is of considerable

interest because of its simplicity and its low cost.

In this work, laboratory corefloods were conducted to study the effect of low

salinity waterflooding on oil recovery rate, residual oil saturation and relative

permeability. Evidence of low salinity enhanced oil recovery was observed

some of these corefloods. Improved oil recovery was generally accompanied

by an increase in water-wetness, based on an observed decrease in end-point

water relative permeability and an increase in end-point oil relative

permeability. Injecting low salinity brine produced a persistent wettability

vi

alteration that eliminated oil recovery salinity dependence in subsequent

floods. However, the sensitivity to salinity was restored by re-aging the core

with the same oil. Tertiary low salinity recovery reported by other researchers

was never observed. Low salinity waterflooding produced no oil recovery

benefit in cores that were initially strongly water-wet.

Based on these results, a working hypothesis is that injecting low salinity

brine induces a wettability alteration from mixed-wet to water-wet in some

cores and that this change improves the oil recovery. More experiments are

needed both to identify the characteristics of the cores that are favorable for

low salinity enhanced oil recovery and to better understand and quantify the

mechanism.

vii

TABLE OF CONTENTS

ACKNOWLEDGMENTS iv

ABSTRACT v

TABLE OF CONTENTS vii

LIST OF TABLES x

LIST OF FIGURES xi

NOMENCLATURE xv

CHAPTER

1. INTRODUCTION 1

2. LITERATURE REVIEW 5

2.1. Early Work with Fresh Water 5

2.2. Wettability 7

2.3. Focused Low Salinity Research Begins 11

2.4. The Oil Industry Takes Notice 14

2.5. Recent Work 18

3. EXPERIMENTAL APPARATUS 26

3.1. Experimental Equipment 26

3.1.1. Pumps 26

3.1.2. Solution Reservoir 27

3.1.3. Oil Reservoir 27

3.1.4. Fraction Collectors 27

3.1.5. Pressure Transducers 28

3.1.6. Pressure Data Acquisition 28

3.1.7. Filter Presses 29

3.1.8. Ovens 29

viii

3.1.9. Core Holders 29

3.2. Analytical Equipment 30

3.2.1. Air Minipermeameter 30

3.2.2. pH Meter 30

3.2.3. Viscometer 31

3.2.4. Conductivity Meter 31

4. EXPERIMENTAL PROCEDURE 34

4.1. Core Preparation 33

4.1.1. Epoxy Encased Cores 33

4.1.2. Core Holder Confined Cores 34

4.2. Air permeability measurement 34

4.3. Fluid Preparation 34

4.3.1. Brine 35

4.3.2. Crude Oil 35

4.4. Brine Saturation 35

4.5. Pore Volume Determination 36

4.5.1. Gravimetric Pore Volume 37

4.5.2. Tracer Measured Pore Volume 37

4.6. Brine Flood 38

4.7. Oil Injection 39

4.8. Aging 39

4.9. Waterflood 39

5. DATA ANALYSIS 41

5.1. Pore Volume Calculation 41

5.1.1. Gravimetric Calculations 41

5.1.2. Tracer Calculations 41

5.1.3. Porosity 42

5.2. Permeability Calculations 42

ix

5.2.1. Brine Permeability 42

5.2.2. Air Permeability 43

5.2.3. Relative Permeability 43

5.3. Phase Saturation Determination 44

5.4. Endpoint Mobility Ratio 45

6. EXPERIMENTAL RESULTS

AND DISSCUSSION 46

6.1. SERIAL WATERFLOODS

IN BEREA CORE 46

6.2. PARALLEL WATERFLOODS

IN BEREA CORES 66


IN RESERVOIR B CORE 88


IN RESERVOIR C CORE 107

7. SUMMARY AND CONCLUSIONS 130

WORKS CITED 145

VITA 150

x

LIST OF TABLES

Table 6.1.1 Experiment 6.1 core properties 51

Table 6.1.2 Experiment 6.1 fluid properties 52

Tables 6.1.3 Experiment 6.1 conditions 53

Tables 6.1.4 Experiment 6.1 results 54



Table 6.2.3 Experiment 6.2 conditions 74

Table 6.2.4 Experiment 6.2 results 76









Table 7.2 Review of experimental data 140

Table 7.1 Buckley-Leverett input data 142

xi

LIST OF FIGURES

Figure 2.1. Residual oil saturation vs. Iw-o for Berea

sandstone, from Anderson2 23

Figure 2.2. Residual oil saturation vs. Iw-o for several

other sandstones, from Anderson2 23

Figure 2.3. Residual oil saturation vs. Iw-o for several

carbonates, from Anderson2 24

Figure 2.4. Effect of wettability on relative permeability,

from Morrow23 24

Figure 2.5. Role of fines in low salinity oil recovery, from

Tang and Morrow29 25

Figure 3.1. Pressure Transducer Configuration 32

Figure 6.1.1. Experimental procedure 55

Figure 6.1.2. Effluent conductivity history 56

Figure 6.1.3. Brine permeability, pressure drop 56

Figure 6.1.4. Pre-age oil flood, pressure drop 57

Figure 6.1.5. Oil flood – 1, pressure drop 57


Figure 6.1.7. Oil flood - 3, pressure drop 58


Figure 6.1.9. HS secondary and LS tertiary – 1, pressure drop 59

Figure 6.1.10. LS secondary – 1, pressure drop 60

Figure 6.1.11. HS secondary and LS tertiary – 2, pressure drop 60

Figure 6.1.12. LS secondary – 2, pressure drop 61

Figure 6.1.13. End-point relative permeabilities 61

Figure 6.1.14. Oil recovery 62

xii

Figure 6.1.15. Oil cut 62

Figure 6.1.16. Average oil saturation 63

Figure 6.1.17. Initial and residual oil saturations 63

Figure 6.1.18. Effluent pH history 64

Figure 6.1.19. Crude A viscosity vs. shear rate 64

Figure 6.1.20. High salinity brine viscosity vs. shear rate 65

Figure 6.1.21. Low salinity brine viscosity vs. shear rate 65


Figure 6.2.2. Flood 1, brine flood pressure drop 77

Figure 6.2.3. Flood 1, oil flood pressure drop 78

Figure 6.2.4. Flood 1, waterflood pressure drop 78


















xiii


Figure 6.3.1. Pictures of core plugs 98


Figure 6.3.3. Effluent conductivity history 99

Figure 6.3.4. Brine permeability, pressure drop 99

Figure 6.3.5. Oil floods, pressure drops 100

Figure 6.3.6.High salinity waterflood – 1, pressure drop 100

Figure 6.3.7. Low salinity waterflood – 1, pressure drop 101

Figure 6.3.8. High salinity waterflood – 2, pressure drop 101








Figure 6.3.16. Crude B viscosity vs. shear rate 105

Figure 6.3.17. SFBRB viscosity vs. shear rate 106

Figure 6.3.18. SLBW viscosity vs. shear rate 106


Figure 6.4.2. PV Tracer, effluent conductivity history 119

Figure 6.4.3. Single phase brine permeability, pressure drop 119

Figure 6.4.4. Oil floods, pressure drops 120






xiv








Figure 6.4.17. Sor Tracer, effluent conductivity history 127

Figure 6.4.18. Crude C viscosity vs. shear rate 128

Figure 6.4.19. SFCRB viscosity vs. shear rate 128

Figure 6.4.20. SLCW viscosity vs. shear rate 129

Figure 7.1. Relative permeability vs. water saturation 143

Figure 7.2. Fractional flow of water vs. water saturation 143

Figure 7.3. Oil recovery 144

Figure 7.4. Oil cut 144

xv

NOMENCLATURE

A Area of core (cm2)

b Klinkenberg gas coefficient (dimensionless)

C Conductivity (Sm-1)

Cinitial Initial conductivity (Sm-1)

Cinjected Injected conductivity (Sm-1)

CD Normalized conductivity (dimensionless)

HS High salinity

HSB High salinity brine

Iw-o Relative wettability index of water and oil (dimensionless)

k Brine pereability (md)

keff,j Effective permeability of j (md)

kg Nitrogen permeability (md)

krj Relative permeability of phase j (dimensionless)

kro Relative oil permeability (dimensionless)

krw Relative water permeability (dimensionless)

kroº End point relative oil permeability (dimensionless)

krwº End point relative water permeability (dimensionless)

L Core length (cm)

xvi

mbrine saturated Brine saturated core's weight (g)

mvacuum Vacuumed core's weight (g)

∆P Pressure drop (psi)

∆Pj Pressure drop of phase j (psi)

P1 Inlet pressure (psi)

P2 Outlet pressure (psi)

P Average pressure (psi)

Psc Pressure at standard conditions (psi)

Pv Pore volume (ml)

Pv,grav Gravimetric pore volume (ml)

Pv,tracer Tracer measured pore volume (ml)

q Flow rate (ml/min)

qj Flow rate of phase j (ml/min)

qsc Flow rate at standard conditions (ml/min)

Sj Saturation of phase j (dimensionless)

Sji Initial saturation of phase j (dimensionless)

So Saturation of oleic phase (dimensionless)

Sor Residual oil saturation (dimensionless)

Sw Saturation of aqueous phase (dimensionless)

Swirr Irreducible water saturation (dimensionless)

xvii

∆Sj Change in saturation of phase j (dimensionless)

TDS Total dissolved solids (ppm)

Vbulk Core bulk volume (ml)

Vtj Total volume of phase j injected into core (ml)

Ve End volume of core (ml)

Greek Symbols

μ Viscosity (cp)

μj Viscosity of phase j (cp)

ρbrine Density of brine (g/ml)

σ Interfacial tension between aqueous and oleic phases

(dynes/cm)

φ Porosity (fraction)

1

CHAPTER 1

INTRODUCTION

Waterflooding is dominant among fluid injection methods and is without

question responsible for maintaining production rate and reserves in North

America.8 As the world’s oil fields mature, waterflooding will continue to be

applied to unlock the enormous endowment of oil reserves left behind by

primary recovery.

The first waterflood occurred as a result of accidental water injection in

Pithole City, Pennsylvannia in 1865.20 Indeed many early waterfloods

occurred accidentally by leaks from shallow water sands or by surface water

entering drilled wells. The first waterflood in Texas was initiated in Brown

County in 1936 and within 10 years waterflooding was in operation in most

North American oil regions.8 By the early 50’s waterflood engineering had

been edified by Leverett’s19, Buckley and Leverett’s6 and Welge’s33

pioneering papers.

When a waterflood is designed, the injected brine is normally chosen because

it is readily available and because it is similar to the native reservoir brine and

therefore will not damage the formation. However multiple researchers3, 4, 11,

2

13, 16, 17, 22, 25, 29, 30, 32, 35, 36, 37 have demonstrated that injecting low salinity brine

can increase oil recovery efficiency in some cases.

Low salinity waterflooding was discovered by researchers at The University

of Wyoming in the 90’s11, 30, 35 doing experiments to determine the affect of

brine, crude oil, mineralogy and experimental procedure on wettability. In the

subsequent decade the technology has repeatedly been proven in the

laboratory16, 25, 29, 36, 37 and in the field.17, 22, 32

The general consensus among researchers is that injecting low salinity brine

creates a wetting state more favorable to oil recovery. Wettability affects the

microscopic distribution and flow of oil and water in porous media and thus

the residual oil saturation. The mechanism(s) responsible for this wettability

alteration are debated.

Even after extensive research, low salinity waterflooding remains quite

controversial. The mechanism(s) responsible is poorly understood, the

reproducibility of published results is doubted and the technology’s scalability

to the field is questioned. Nonetheless, low salinity waterflooding is appealing

because it could offers considerable recovery benefit, is relatively low cost

and is relatively simple compared to other chemical EOR techniques.

3

This research effort was undertaken to study the effect of low salinity

waterflooding on oil recovery rate, residual oil saturation and relative

permeability. This effort has consisted of 21 different waterfloods using nine

brines, three crude oil, six outcrop Berea cores and two oil reservoir cores.

The results provide a foundation for future research.

Four experiments were performed: Serial floods in Berea core, Parallel floods

in Berea cores, Serial floods in Reservoir B core and Serial floods in

Reservoir C core. The serial experiments were conducted in the same core,

one after another, to eliminate the possibility that natural variations between

cores were responsible for any contrasts between the high salinity and low

salinity results. The parallel experiments were conducted in separate cores to

evaluate the affect of different injection brine cation composition. Separate

cores were necessary because injecting low salinity brine could alter a crude

oil/rock/brine system’s wettability and thus affect subsequent injections.

Evidence of low salinity enhanced oil recovery was observed in a few cases.

Improved recovery was generally accompanied by an increase in water-

wetness, based on an observed decrease in krwº and an increase in kroº. In the

serial experiments injecting low salinity brine produced a persistent

4

wettability alteration that eliminated oil recovery salinity dependence in

subsequent floods. However, sensitivity to salinity was restored by re-aging.

Tertiary low salinity recovery reported by other researchers25, 29, 36, 37 was

never observed.

5

CHAPTER 2

LITERATURE REVIEW

Multiple researchers3, 4, 11, 13, 16, 17, 22, 25, 29, 30, 32, 35, 36, 37 have observed a

reduction in residual oil saturation when low salinity brine is injected instead

of high salinity brine. However after decades of research, the mechanisms

responsible are still uncertain.

In the laboratory, when a waterflood is performed in the secondary mode it

means it is the first injection post-oil flood. A waterflood performed in the

tertiary mode is performed after the secondary mode injection.

2.1 Early Work with Fresh Water

Researchers4, 21 began injecting fresh water into core samples almost a half

century ago. Researchers hoped to better understand the effect of authigenic

clay content and studied the impact of fresh water on permeability and oil

recovery.

6

Martin21 injected fresh water into Maracaibo Basin and East Texas Woodbine

reservoir cores to study the effects of clay content on recovery efficiency and

relative permeability. Several cores were flooded with cycles of toluene and

fresh water to remove clay materials. The cores were flooded with heavy oil

then the oil was displaced with fresh water. The pre-treated cores had lower

irreducible water saturations and higher water relative permeabilites. The

treated and untreated cores had similar residual oil saturations and oil relative

permeabilites. Permeability to fresh water decreased over the course of several

hours or days after the fresh water injection was initiated. The original water

permeability could be restored momentarily by reversing the flow direction,

suggesting pore throat plugging by migrating fines. Martin proposed that in

the clay-rich cores a clay-water dispersion was created with a higher apparent

viscosity and lower water relative permeability then the free water.

Bernard4 injected NaCl brine and distilled water into sandpacks, Berea cores

and outcrop cores from Wyoming. Initial oil saturation was established with

Soltrol oil then NaCl brine or distilled water was injected. In constant flow

rate experiments, injecting distilled water increased recovery in both the

secondary and tertiary modes. The increased recovery was always

accompanied by a massive increase in pressure drop; three orders of

magnitude in one case. NaCl brine and distilled water produced similar

7

recoveries in constant pressure drop experiments. Bernard attributed the

increased recovery to improved microscopic sweep efficiency induced by clay

swelling and plugging of pore throat by migrating fines.

2.2 WETTABILITY

Wettability is defined as “the tendency of one fluid to spread on or adhere to a

solid surface in the presence of other immiscible fluids.”8 When the fluids are

water and oil, the wettability is the tendency for the rock to preferentially

imbibe oil, water or both.2

Many different degrees of wettability have been presented in the literature. A

rock is water-wet if the aqueous phase will be retained by capillary forces in

the smaller pores and on the walls of the larger pores and the oleic phase

occupies the center of the larger pores and form globules that might extend

over many pores. A rock is neutrally-wet if there is no preference for one fluid

or another. A rock is fractionally-wet if it is composed of different minerals,

each with different surface chemistry and adsorption properties, which can

lead to wettability variations.2 A rock is mixed-wet if the oleic phase

completely occupies the large pores and the aqueous phase occupies the small

pores or if different minerals within the same pore are wet by different

8

fluids.26 And lastly, a rock is oil-wet if the oleic phase occupies the small

pores and coats the walls of the large pores and the aqueous phase occupies

the center of the larger pores. According to Jarrell et al.12 oil-wet reservoirs do

not occur naturally and all reservoirs that claim to be oil-wet are actually

mixed-wet because the oleic phase does not occupy the small pores.

Wettability can be indexed with the Amott wettability test.1 The Amott

wettability index (Iw-o) is obtained by a combined imbibition and displacement

test. It ranges from +1 to -1, with a +1 indicating a strongly water-wet and a -

1 indicating a strongly oil-wet.

The affect of wettability, measured with the Amott index, on residual oil

saturation has been studied experimentally by several researchers.7, 9-11, 14, 23, 24,

31 Figures 2.1 – 2.3 display experimental data for Berea sandstone, other

sandstones and several carbonates. The residual oil saturation is lowest when

the wettability is nearest to neutral or mixed-wet.

The relative permeability of a wetting phase is lower then the relative

permeability of a non-wetting phase. If a crude oil/rock/brine system becomes

more water-wet, the water relative permeability will decrease while the oil

9

relative permeability will increase. Morrow23 illustrated this with relative

permeability data fit to Corey type functions shown in Figure 2.4.

Prior to the heralding of low salinity enhanced oil recovery, researchers

manipulated brine composition to better understand the factors that determine

a crude oil/rock/brine system’s wettability.

Jadhunandan and Morrow11 studied the relationship between waterflood oil

recovery and wettability. Wettability was modified by adjusting the aging

temperature, initial water saturation, brine composition and crude oil. Berea

sandstone cores and 3 different oils were used. Brines were composed of

NaCl, CaCl2 and a trace concentration of sodium azide. All brines possessed

high salinity, only the Na/Ca ratios were adjusted. Fifty crude oil/brine/rock

systems were tested. Maximum oil recovery by waterflooding was obtained at

very weakly water-wet conditions. Wettability was measured after waterflood

with the Amott method.1 Iw-o decreased with increasing calcium-ion content

with the Moutray crude oil. Wettability was insensitive to Ca2+ with the other

oils. With both crudes Iw-o increased with increasing Swi, and Iw-o decreased

with increasing aging temperature.

10

Yildiz and Morrow35 conducted corefloods using Berea sandstone, Moutray

crude oil and either a Na brine composed of 4% NaCl + 0.5% CaCl2 or a Ca

brine composed of 2% CaCl2. Recovery was higher with the Ca brine when

the connate and injected brines were identical. The highest recovery was

achieved by initially saturating the core with Ca brine, injecting Na brine until

residual oil saturation was achieved, then injecting Ca brine. Almost 13%

incremental recovery was achieved about 1 PV after the start of the tertiary Ca

brine flood. Wettability was measured after waterflood with the Amott

method.1 Greater waterflood recovery was achieved in mixed-wet cores.

Spontaneous imbibition of Na brine was 4 times greater then Ca brine after

about 2 days.

Tang and Morrow30 investigated the effects of connate and injection brine

salinity, aging time and temperature on waterflooding and imbibition with 3

different crude oils and 3 different brines. In imbibition experiments with

identical connate and invading brines, decreasing the salinity of both brines

produced higher final recovery. In experiments with constant connate brine

salinity and variable invading brine salinity, decreasing invading brine salinity

increased recovery. In experiments with variable connate brine salinity and

constant invading brine salinity, decreasing connate brine salinity increased

recovery.

11

In waterfloods with identical connate and injected brines, decreasing the

salinity of both brines produced higher recovery primarily by delaying

breakthrough. In waterfloods with constant connate brine salinity and variable

injected brine salinity, diluting injected brine 100 times produced ~5%

incremental oil recovery. In waterfloods with variable connate brine salinity

and constant injected brine salinity, decreasing connate brine salinity

dramatically improved recovery – about 40% incremental oil recovery was

achieved by diluted the connate brine 100 times.

Increasing aging time increased recovery by spontaneous imbibition and

decreased waterflood recovery. Increasing experiment temperature produced

higher oil recovery by spontaneous imbibition and waterflood.

2.3 Focused Low Salinity Research Begins

Based on these findings researchers, began to focus on the only variable that

can be manipulated in a reservoir – the injection brine salinity. Researchers

noticed that improved recovery by injection of low salinity brine only

occurred when crude oil and clay bearing sandstone mineralogy were present.

12

Based on this observation, Tang and Morrow29 offered the first theoretical

interpretation of the mechanism responsible.

Tang and Morrow29 observed an increase in waterflood and spontaneous

imbibition recovery with a decrease in salinity in numerous cases. The authors

used Berea, Bentheim, CS Reservoir, Clashach and fired and acidized Berea

cores, CS crude and refined oil and 7 different brines ranging from 35,960

ppm TDS to 151.5 ppm TDS.

Recovery improved significantly in the CS reservoir and Berea cores when

low salinity brine was injected instead of high salinity, but recovery improved

only marginally in the more clay free Bentheim and Clashach cores. Berea

cores that were fired and acidized, to stabilize fines, were insensitive to brine

salinity. Cores that were repeatedly waterflooded produced fines and were

sensitive to brine salinity in early waterfloods, but stopped producing fines

and were insensitive to brine salinity in late waterfloods. Cores initially 100%

saturated with crude oil – with fines completely immersed in the oil phase –

were insensitive to brine salinity. And lastly, cores saturated with refined

mineral oil, rather then crude oil, were insensitive to salinity.

13

Tang and Morrow conclude that heavy polar components in the crude oil

adsorb onto fine particles along the pore walls and that these mixed-wet fines

are stripped by low salinity brine, altering wettability and increasing oil

recovery. A figure from their paper illustrating the proposed mechanism is in

Figure 2.5.

Zhang and Morrow36 conducted waterflood and spontaneous imbibition

experiments using 4 different samples of Berea sandstone and three different

crude oils. These authors observed improved recovery by injecting low

salinity brine in secondary and tertiary modes. The impact of low salinity

brine varied significantly between the different samples of Berea, suggesting

that mineralogy was the most important variable affecting improved recovery.

The lowest permeability block of Berea (knitrogen ~ 60 to 140 md) showed no

sensitivity to salinity. The lack of response was attributed to the presence of

chlorite. In several cases, cores responded to low salinity brine in the

secondary but not the tertiary mode. Low salinity effects become more

dramatic as the initial water saturation increased. In all cases, injection of low

salinity brine was accompanied by an increase of pressure followed by a

gradual decrease. Effluent pH also increased.

14

Publications indicating no benefit of low salinity waterflooding are also

present in the literature. Sharma and Filoco27 investigated the impact of

connate and injection brine salinity and crude oil on oil recovery, residual

saturations and wettability using Berea cores, 3 different oils and NaCl brine

in various concentrations.

In imbibition experiments decreasing connate brine salinity increased

recovery and significantly affected relative permeability. The salinity of the

displacing brine had no significant impact. Drainage experiment’s recovery

and relative permeability were insensitive to salinity. During waterflooding of

crude oil, oil recovery increased with decreasing connate brine salinity.

However, during waterflooding of mineral oil, recovery was insensitive to

connate brine salinity. In all cases, waterflood recovery was insensitive to the

salinity of the injected brine.

Sharma and Filoco suggested that low salinity connate brine changes the

wetting properties of the rock surface from water-wet to mixed-wet and

thereby decreases residual oil saturation.

2.4 The Oil Industry Takes Notice

15

Encouraged by results from at The University of Wyoming, researchers at BP

began to evaluate the applicability of low salinity waterflooding at the field

scale. Numerous core floods and single well tests were preformed, a

mechanism was proposed, a computer model was created and an interwell test

was conducted.

Webb et al.32 observed a reduction in residual oil saturation in the near well

bore region by injecting low salinity brine. Three different brines were

injected into a clastic formation from a producing well. Saturation was

measured after each injection using a pulsed neutron capture log. A base line

Sor was established with a synthetic native brine (250,000 ppm). Synthetic sea

water (120,000 ppm), injected second, did not reduce oil saturation further. A

low salinity brine (3,000 ppm), injected last, reduced Sor significantly in two

sand intervals and slightly in another.

McGuire et al.22 confirmed the low salinity induced Sor reduction in the near

well bore region. Experiments were carried out from four different wells in a

clastic North Slope reservoir. Saturations were measured using single well

chemical tracer tests (SWCTT) after a high salinity flood then again after a

low salinity flood. In all four cases residual oil saturation decreased after the

low salinity flood. On the basis of the increase in the pH of the effluent brine,

16

the authors proposed that saponification caused production of natural

surfactants that increased recovery by reducing interfacial tension.

Jerauld et al.13 created a model that included salinity dependent residual oil

saturation and relative permeability. Using coreflood and SWCTT data

researchers correlated the incremental benefit of low salinity waterflooding

with kaolinite fraction. Residual oil saturation, relative permeability and brine

density and viscosity were made functions of salinity. Simulation results are

strongly affected by dispersion because of the salinity dependence. The

simulation successfully history matched single well and coreflood

experiments.

Lager et al.16 achieved improved waterflood recovery by injecting low salinity

brine in secondary and tertiary modes. Fines migration or significant

permeability reduction because of low salinity injection were never observed,

leading Lager et al. to question the link between fines migration and oil

recovery proposed by Tang and Morrow.29 A 40% increase in recovery was

observed using a North Sea crude with a very low acid number (AN < 0.05),

leading Lager et al. to dismiss the low salinity induced alkali flooding

hypothesis proposed by McGuire et al.22

17

In several experiments Lager et al. noticed a significant drop in Ca2+ and Mg2+

effluent concentration during a low salinity waterflood. Researchers saturated

a North Slope core with synthetic reservoir brine and crude, then achieved a

35% OOIP recovery with a high salinity brine flood. The same core was

restored and repeatedly flushed with NaCl-only brine to replace all the

multivalent cations present on the mineral surface, then flooded with crude.

The ensuing high salinity waterflood achieved a higher recovery of 48%

OOIP and subsequent low salinity tertiary floods produced no additional oil.

These results prompted Lager et al. to suggest multi-component ionic

exchange was responsible for the increase in oil recovery. The authors cite 4

different mechanisms that could sequester oil: cation exchange, ligand

bonding, cation bridging and water bridging, and suggest that the strength of

all is reduced when contacted with low salinity brine.

Lager et al.17 conducted a low salinity interwell field test in a sandstone oil

reservoir. The experiment was carried out between 1 injector and 2 producers.

Oil rate had fallen to 150 bbl/day after natural depletion, a standard

waterflood and a flood of miscible injectant. In May 2005, low salinity water

injection began. About 6 months later the oil rate at one of the producers

began to rise; peaking at 320 bbl/day. Water chemistry also changed

dramatically with the arrival of the oil bank. Magnesium ion concentration fell

18

from 0.75 meq/l to less then 0.01 meq/l, maintained this low level for 5

months, then rose back to 0.5 meq/l. Pore volume was measured with barium

ion tracers; the low salinity induced oil bank arrived after about 0.3 PV

injected – in good agreement with experimental data. The other producer

showed no response perhaps due to a sealing fault between it and the injector.

No loss of injectivity was reported, implying no formation damage.

Researchers also carried out a SWCTT: reducing a high salinity Sor of

0.30±0.02, to 0.28±0.02 with a non optimized low salinity brine, then further

to 0.20±0.02 with an optimized low salinity brine, highlighting the importance

of cation selection.

2.5 Recent work

As more and more low salinity experiments were conducted the importance of

mineralogy – specifically clay content – continued to be emphasized, but a

comprehensive and predictive mechanistic model remained unavailable. Many

recent experiments have been conducted in candidate reservoir core because

low salinity response remains difficult to forecast. Researchers observed

dramatic results with clay-rich sandstone reservoir cores and, for the first

time, in almost clay free cores.

19

Zhang et al.37 reported increased recovery in the tertiary mode by reducing

reservoir brine salinity 20 times. Two consolidated reservoir sandstone cores

were used. X-ray diffraction indicated that each of the cores were rich in chert

and kaolinite. Two different crudes and a mineral oil were used.

Almost 70% incremental oil recovery was achieved in the secondary mode.

Both the high and low salinity secondary floods were conducted in the same

core. Tertiary recovery was also quite large; 25% incremental recovery in the

best case. The recovery was achieved slowly, taking more then 10 injected

pore volumes. In several cases the pH fell upon injection of low salinity brine;

contrary to other researcher’s observations. Pressure drop was closely tied to

incremental recovery. In all cases where significant incremental recovery was

achieved pressure drop increased significantly then fell gradually.

Pu et al.25 observed low salinity tertiary recovery from an almost clay free

core for the first time. Researchers injected coalbed methane (CBM) water

into 3 sandstone reservoir cores composed of quartz, feldspar, dolomite and

anhydrite cements but which had very little clay. The CBM water’s salinity

was about 1,316 ppm TDS. Cores were first waterflooded with high salinity

formation brine (38,651 ppm). When oil production to high salinity brine

ceased CBM water was injected.

20

In all cases CBM water liberated additional oil. In each core the benefit of

tertiary low salinity flooding became less dramatic after each flood and

restoration. A core was acidized to remove dolomite crystals and subsequently

its recovery became insensitive to low salinity flooding. Pu et al. proposes that

dolomite crystals play an important role in the low salinity recovery

mechanism. Some of the dolomite crystals become mixed-wet as they

contacted the oil phase during aging. During the low salinity flood the

dolomite crystals may detach from the pore walls releasing oil from the rock

surface. The detached dolomite crystals will then reside at the crude oil/brine

interface increasing resistance to flow of brine at the interface, delay snap-off

at pore-throats and preventing the collapse of oil lamella.

Agbalaka et al.3 conducted waterflood experiments to study the recovery

benefit of using low salinity brine. Researchers used Berea sandstone and

Milne Point Unit cores. 4%, 2% and 1% NaCl brine and Trans Alaskan

Pipeline System (TAPS) crude oil and refined decane spiked with TAPS crude

were used.

Incremental oil was recovered in tertiary mode by switching from 4% to 2%

to 1% NaCl brine. Improved recovery was also achieved by injecting low

21

salinity brine in the secondary mode. Pressure drop data was unpublished.

Researchers measured wettability with the Amott method1 and found an

increase in the degree of water-wetness with a decrease in NaCl concentration.

Injection of low salinity brine has improved waterflood recovery in numerous

laboratory and field experiments. The general consensus among researchers is

that injecting low salinity brine creates a wetting state more favorable to oil

recovery. Wettability affects the microscopic distribution and flow of oil and

water in porous media and thus the residual oil saturation. The mechanisms

responsible for this wettability alteration are debated. Tang and Morrow29

hypothesized heavy polar components in the crude oil adsorb onto fine

particles along the pore walls and that these mixed-wet fines are striped by

low salinity brine. Lager et al.16 concluded that increased recovery resulted

from low salinity induced multi-component ionic exchange that caused

reduction in ion binding between the crude oil and the rock surface. Pu et al.25

proposed that during a low salinity flood mix-wet dolomite crystals detach

from the pore walls releasing oil from the rock surface. The detached

dolomite crystals will then reside at the crude oil/brine interface increasing

resistance to flow of brine at the interface, delay snap-off at pore-throats and

preventing the collapse of oil lamella.

22

Mechanisms not involving wettability alteration have also been suggested.

Bernard4 attributed the increased recovery to improved microscopic sweep

efficiency induced by clay swelling and plugging of pore throat by migrating

fines. However the massive pressure drop increases suggest a reduction in

residual oil saturation due to capillary desaturation. McGuire et al.22 proposed

that saponification caused production of natural surfactants that increased

recovery through reduction of interfacial tension. However low salinity

flooding has reduced residual saturation in cores containing crudes with

extremely low acid numbers and in cores where effluent pH decreased as the

low salinity bank arrived at the outlet.

23

Figure 2.1. Residual oil saturation vs. Iw-o for Berea sandstone, from Anderson28

Figure 2.2. Residual oil saturation vs. Iw-o for several other sandstones, from Anderson28

24

Figure 2.3. Residual oil saturation vs. Iw-o for several carbonates, from Anderson28

Figure 2.4. Effect of Wettability on Relative Permeability, from Morrow39

25

Figure 2.5. Role of fines in low salinity oil recovery, from Tang and Morrow7

26

CHAPTER 3

EXPERIMENTAL APPARATUS

Two general categories of experimental equipment were used in this research:

1. Equipment to perform the experiments, including pumps, solution

reservoirs, a fraction collector, transducers, data acquisition, an air

minipermeameter, filter presses, ovens and core holders.

2. Equipment to analyze fluid samples, including a pH meter, a

viscometer, and a conductivity meter.

3.1 EXPERIMENTAL EQUIPMENT

3.1.1 Pumps

A Teledyne Isco 500 D Syringe Pump was used. The pump provided flow

rates between 31.00 10−× and 22.04 10× ml/min with a maximum output

pressure of 3750 psi and 507 ml of total capacity. Teledyne pumps use

corrosion resistant stainless steel for cylinders and pistons and heavy duty

Teflon seals. The pump exclusively pumped mineral oil to avoid internal

cleaning.

27

3.1.2 Solution Reservoir

Kontes Chromaflex Columns, made of borosilicate glass and Teflon end

pieces, were used as fluid reservoirs for brine. The pressure rating for each

column was 40 psi and the capacity was 543 ml. To inject solution into a core

the column was oriented vertically and mineral oil from the pump was

injected into the top, displacing the more dense brine which exited the column

at the bottom.

3.1.3 Oil Reservoir

Stainless steel columns with Swagelok fittings on each end – manufactured in

The University of Texas Petroleum and Geosystems Engineering Department

machine shop – were used as oil reservoirs. The columns were approximately

2’ long, 1” OD, and 1/8” thick and had a pressure rating well in excess of 100

psi. To inject oil into a core the column was oriented vertically and

compressed air was injected into the top, displacing the more dense oil phase

which exited the column at the bottom.

3.1.4 Fraction Collectors

28

A Spectrum Chromatography Fraction Collector was used to collect effluent

fluid samples. The fraction collector had a capacity of 174 - ten ml test tubes.

The fraction collector positioned a test tube to receive fluid for a preset

amount of time. After the time expired, a new test tube was positioned to

receive fluid. During most experiments the time allotted for each sample was

set so that approximately 8 ml of fluid was collected in each test tube.

3.1.5 Pressure Transducers

Differential pressure transducers were used to measure pressure drop between

pressure taps on the core. The transducers measure differential pressure by

detecting the deflection of an internal diaphragm and converting the

information to an output voltage. Four 0 to 10 psid, one 0 to 50 psid and one 0

to 300 psid Cole-Parmer Wet/Wet Differential Pressure Transmitters were

used. Figure 3.1 shows the configuration of the core and the transducers.

3.1.5 Pressure Data Acquisition

Voltage signals from the pressure transducers were input to a National

Instruments USB-6008 8-input, 16-bit, 10kS/s Multifunction I/O board. The

29

I/O board was connected to a desktop computer via a USB cable where a

labVIEW program recorded differential pressure at preset time intervals.

3.1.6 Filter Presses

Oil samples were filtered using a stainless steel OFITE low pressure filter

press. Oil was forced through filter paper at the bottom of the filter by

compressed air injected at the top of the filter.

Brine solutions were filtered with a Millipore Vacuum Filter. Brine was pulled

through filter paper by a vacuum pump.

3.1.7 Ovens

Coreflood experiments and aging intervals were conducted inside an oven

when elevated temperature was required. The ovens possessed digital

temperature set points and thermometers. Temperature was also independently

measured to ensure accuracy.

3.1.8 Core Holders

30

A 1.5” internal diameter core holder manufactured by Phoenix Instruments

was used. The core holder was manufactured with 316 stainless steel and was

rated for 2,000 psi and 150ºC. Three pressure taps were placed seven cm apart

from each other.

3.2 ANALYTICAL EQUIPMENT

3.2.1 Air Minipermeameter

Air permeability was measured using a minipermeameter constructed in the

Petroleum and Geosystems Engineering Department at The University of

Texas. The permeameter measures flow rate and inlet pressure.

3.2.2 pH meter

pH was measured using a Thermo Scientific Orion 4-Star pH/Dissolved

Oxygen Benchtop Meter. To take a measurement a pH probe was dipped into

a sample. The sample was gently agitated until a steady reading was obtained.

The meter was calibrated before each measurement with standard buffers of

pH 3.00 and pH 7.00.

31

3.2.3 Viscometer

Bulk viscosity was measured using the Contraves Low Shear 30 viscometer.

The instrument measures the shear stress between a spinning cup and bob and

calculated fluid viscosity. Approximately 0.9 ml of fluid was required for each

measurement. Viscosity was measured over a range of shear rates, from

0.0237 to 69.5 sec-1 and at the experiment temperature. Viscosity measure at

11 sec-1 was used in subsequent calculation because this shear rate is most

representative of an oil reservoir.

3.2.4 Conductivity meter

A Fisher Scientific TraceableTM meter was used to measure conductivity. The

meter’s probe was submerged in a sample and an electric field was induced.

The meter measured voltage drop between a current electrode and a pickup

electrode and calculated conductivity.

32

Figure 3.1. Pressure Transducer Configuration

33

CHAPTER 4

EXPERIMENTAL PROCEDURE

4.1 CORE PREPARATION

Cores were either encased in epoxy or placed inside a core holder.

4.1.1 Epoxy encased cores

To prepare epoxy encased cores, first polycarbonate plastic endpieces were

fabricated. The endpiece faces which contacted the core were milled to a

depth of 1/16 inches to ensure adequate fluid contact across the entire core

face. Epoxy resin was prepared by mixing 2 parts EPONTM Resin 828 and 1

part VersamidR 125 Hardener by weight, obtained from Miller Stephen. The

core was placed inside a hollow polycarbonate plastic cylinder, 2.5 inches in

diameter, and epoxy resin was poured between the cylinder and core. Or the

core was placed inside a polyethylene mold and the mold was filled with

epoxy resin. The layer of epoxy resin was sufficiently thick to allow the core

to withstand approximately 50 psi. The epoxy resin was allowed to cure for

about a day. After curing, inflow and outflow holes and pressure taps were

connected to 1/8-inch NPT fittings.

34

4.1.2 Core holder confined cores

Both outcrop cores and reservoir core plugs were confined in a core holder.

Reservoir core plugs were first stacked to achieve the desire core length.

Cores were wrapped in several layers of tylon tape and encased in heat shrink

plastic. High porosity metal screens were placed at the inlet and outlet faces to

prevent core damage. Cores were inserted into the coreholder and subject to

about 1000 psi of confining pressure applied with mineral oil and a hydraulic

hand pump.

4.2 AIR PERMEABILITY MEASUREMENT

Air permeability was measured using the minipermeameter described in

Chapter 3.2.1. Compressed nitrogen was injected into the prepared cores at a

range of flowrates. A rotameter was used to measure the flowrate of gas. An

analog pressure dial was used to measure pressure drop. Air permeability was

calculated with a spreadsheet which accounted for Klinkenberg15 effect.

4.3 FLUID PREPARATION

35

4.3.1 Brine

DI water and salts were mixed in the appropriate proportions. Normally 3.5 L

of brine were mixed at a time. Every brine sample was filtered with the

Millipore vacuum filter. Brine was poured into that filtration apparatus and a

vacuum pump pulled the fluid through a Millipore HA, 47-mm 0.45 micron

nominal pore opening cellulose filter.

4.3.2 Crude oil

Every oil sample was filtered with the OFITE filter press. The oil was forced

through a Millipore HA, 47-mm 0.45 micron nominal pore opening cellulose

filter. With Crude A it was necessary to first filter the oil with 5.0 micron

filter paper, then 1.2 micron filter paper and finally with 0.45 micron filter

paper.

4.3 BRINE SATURATION

After core preparation and air permeability measurement the following steps

were taken to saturate the core with brine:

36

• The core was flooded with several pore volumes of CO2 gas to remove

oxygen.

• A vacuum pump was connected to the outflow valve and a vacuum

pressure gauge was connected to the inlet valve, all other valves were

closed. The core was evacuated for about half an hour, then the

vacuum pump was turned off and the core pressure was monitored to

check for leaks.

• If the vacuum was maintain for another half hour the core inflow was

attached to a burette containing brine. The inflow valve was opened

and brine was sucked into the core. The inflow was shut when no more

brine would enter the core and the volume of brine imbibed was

recorded.

4.4 PORE VOLUME MEASUREMENT

Pore volume was measured in three ways: volumetrically, gravimetrically and

with a salinity tracer.

4.4.1 Volumetric pore volume

37

After the core was vacuumed the volume of brine imbibed was measured.

Because of dead volume, especially in the core holder, the volumetric pore

volume is inaccurate. The volumetric pore volume was used mostly to check

if the core was thoroughly saturated.

4.4.2 Gravimetric pore volume

Pore volume was measured gravimetrically when cores were encased in

enamel. Cores were weighed twice: when evacuated and when saturated with

brine. The difference in weight between the vacuumed and saturated core,

divided by the brine density, is the gravimetric pore volume.

4.4.3 Tracer measured pore volume

Pore volume was measured with a salinity tracer when cores were placed

inside a core holder. The core was initially saturated and flooded with 1.0%

NaCl and 0.3% CaCl2 tracer brine. Then high salinity connate brine was

injected and effluent samples were collected. Effluent conductivity was

measured and normalized by the initial and injected conductivities. Pore

volume was calculated using Equation (5.3). Brine was injected using the

solution reservoir arrangement described in Chapter 3.1.2.

38

4.5 TRANSDUCER CALIBRATION

Pressure transducers were calibrated before every injection. The following

procedure was used:

• Pressure transducer lines were loosely attached to the core and

transducer bypass valves were opened.

• Brine was driven through the transducer line from an elevated

reservoir to force air bubbles out of the system.

• Transducer lines were tightened one at a time after air bubbles had

been expelled and the elevated reservoir was disconnected.

• Transducer offsets were adjusted until the differential pressure across

each transducer was zero.

• The transducer bypass valves were closed.

4.6 BRINE FLOOD

After pore volume was measured, temperature was elevated to experiment

temperature. Cores were flooded with at least 5 pore volumes of connate

brine. Brine was injected using the solution reservoir arrangement described

in Chapter 3.1.2. The cores were oriented vertically and the brine was injected

39

at the bottom. Flowrate was regularly measured volumetrically with a burette

and stop watch. Pressure drop was measured with transducers.

4.7 OIL FLOOD

Oil floods were conducted at constant injection pressure and at experiment

temperature. The cores were oriented vertically and oil was injected at the top.

Oil was injected using the oil reservoir arrangement described in Chapter

3.1.3. Produced oil and water were collected in burettes. Oil-water and air-oil

interfaces were recorded to calculated saturation. Flowrate was regularly

measured with a stop watch. Pressure drop was measured with transducers.

4.8 AGING

Oil saturated cores were aged at an aging temperature. Cores were normally

aged for several days to allow the crude oil, brine and rock to equilibrate.

After aging experiment temperature was restored.

4.9 WATERFLOOD

40

Comparing the results of high salinity and low salinity waterfloods was the

principle aims of this research. Injection rates were sufficiently slow to avoid

the oil mobilizing region of the capillary desaturation curve. HS and LS brines

were injected using the solution reservoir arrangement described in Chapter

3.1.2. Normally about 5 to 7 pore volumes of water were injected. After 5 to 7

pore volumes oil production had completely ceased or was less then 0.1%.

Sample were collected with a fraction collector in 10 ml test tubes so that

accurate recovery vs. time data could be calculated. Each test tube’s oil-water

and air-oil interface was recorded, permitting the calculation of production

rate, oil cut, oil recovery and average saturation. Pressure drop was measured

with transducers.

41

CHAPTER 5

DATA ANALYSIS

5.1 Pore Volume and Porosity Calculation

5.1.1 Gravimetric Calculations

The gravimetric pore volume is equal to the difference in weight between the

dry and saturated core, divided by the brine density.

,vacuumbrine saturated

v gravbrine

m mP

ρ−

= (5.1)

5.1.2. Tracer Calculations

The conductivity tracer pore volume is equal to the breakthrough of the

injected conductivity. Conductivity is first normalized to the initial and

injected conductivity.

initialD

injected initial

C CCC C

−=

− (5.2)

42

Because the conductivity vs. volume curve is asymmetric, normalized

conductivity is plotted vs. volume injected and the area above the curve is

integrated to determine the breakthrough and pore volume.

( ), 01v tracer D injP C dV

∞= −∫ (5.3)

5.1.3. Porosity

Porosity is calculated with either the gravimetric or tracer measured pore

volume and the bulk volume. The bulk volume is measured with calipers.

v

bulk

PV

ϕ = (5.4)

5.2 Permeability Calculation

5.2.2 Brine Permeability

Permeability of the core at 100% brine saturation is used as the reference

permeability. Darcy’s law for single-phase, steady-state, incompressible,

horizontal flow is:

kA PqLμΔ

= (5.5)

43

and in laboratory units of cc/min, md, cm2, psi, cp and cm:

245kA Pq

LμΔ

= (5.6)

5.2.1 Air Permeability

Nitrogen permeability is calculated with a modified version of Darcy’s Law:

( )2 21 2

2 sc scg

q LPkA P P

μ=

− (5.7)

The permeability determined from Equation (5.5) is usually higher than the

brine permeability because of an electro-kinetic phenomenon known as the

Klinkenberg15 effect. The gas permeability is related to the brine permeability

by:

1gbk kP

⎛ ⎞= +⎜ ⎟⎝ ⎠

(5.8)

and

1 2

2P PP +

= (5.9)

5.2.3 Relative Permeability

44

Permeability to each flowing phase in the presence of another phase is defined

as the effective permeability to that phase and is calculated using:

,j j j

eff jj

q Lk

A Pμ

=Δ

(5.10)

Effective permeabilites for each phase were normalized to 100% brine

permeability for relative permeability calculations.

,eff jrj

kk

k= (5.11)

5.3 Phase Saturation Determination

For each injection sequence, fluids were injected until steady-state was

achieved. Steady-state conditions are summarized as follows:

• Constant flow rates

• Constant phase fractional flow

• Constant pressure drop

• Production of fluids with the same composition as that of the injected

fluids

Saturations were then calculated using the material balance equations.

45

Volumes of each phase in the effluent samples were read from test tubes or

burettes. These volume readings were used to calculate saturation, fractional

flow and flow rate of each phase. Saturations were estimated with a material

balance on each phase. Assuming that there is no phase partitioning, no

adsorption, and that the fluids are incompressible, the volume balance for

phase j is:

( )tj e j jiV V PV S S− = − (5.12)

which yields that change in saturation of phase j:

tj ej

v

V VS

P

⎡ ⎤−⎣ ⎦Δ = (5.13)

5.4 Endpoint Mobility Ratio

The endpoint mobility ratio for oil and water is a measure of the stability of

the displacement of oil by water injection. The endpoint mobility ratio is

defines as:34

rw o

ro w

kMk

μμ

= (5.14)

46

CHAPTER 6

EXPERIMENTAL RESULTS AND DISSCUSSION

6.1 SERIAL WATERFLOODS IN BEREA CORE

In this experiment a sequence of two high salinity secondary, two low salinity

secondary and two low salinity tertiary waterfloods were conducted in a single

Berea sandstone core. The objective of this experiment was to evaluate the

effect of low salinity injection on recovery rate, residual oil saturation and

relative permeability. The waterfloods were conducted in the same core,

serially, to eliminate the possibility that natural variations between cores were

responsible for any contrasts between the high and low salinity results.

A single core was cut from a block of visually homogeneous Berea sandstone.

Two brines were used during waterflood experiments. A high salinity brine

(HSB) with 29,700 ppm TDS and a low salinity brine (LSB) with 1140 ppm

TDS. Both brines had a nearly equal equivalent-molar ratio of Na and Ca.

Also an oxygen scavenger, sodium dithionite, was included in every brine

reduce redox potential. Properties of the core and fluids are given in Tables

6.1.1 and 6.1.2, respectively.

47

The following procedures, described in detail in Chapter 4, were employed.

The core was confined inside a core holder and permeability to nitrogen gas

was measured. Pore volume was measured with a salinity tracer. The core was

vacuum saturated with tracer brine then several additional pore volumes of

tracer brine were injected. Temperature was elevated to 55ºC. HSB was

injected, the effluent fluid was sampled and pore volume and permeability

were calculated. Crude A was injected to establish Soi then the saturated core

was aged for 2 days at 75ºC.

Temperature was reduced to 55ºC and the following floods were conducted:

• Oil flood – 1

• HS secondary and LS tertiary – 1 (HSS and LST – 1)

• High salinity connate brine restoration

• Oil flood – 2

• LS secondary – 1 (LSS – 1)


• Oil flood – 3

• HS secondary and LS tertiary – 2 (HSS and LST – 2)


• Oil flood – 4

48

• LS secondary – 2 (LST – 2)

A diagram of the experimental procedures is in Figure 6.1.1. Experimental

conditions are in Table 6.1.3.

Figure 6.1.2 displays the effluent conductivity history. Figure 6.1.3 displays

the pressure drop during the HS connate brine flood. Porosity and

permeability were 21.9% and 471 md, respectively.

Five oil floods were conducted: the pre-age oil flood and oil floods 1 – 4. The

pressure drops during the oil floods are displayed in Figures 6.1.4 – 6.1.8.

Pressure data during most of oil flood – 2 was inadvertently unrecorded. Four

waterfloods were conducted: HS secondary and LS tertiary – 1 and 2, and LS

secondary – 1 and 2. The pressure drops during the waterfloods are in Figure

6.1.9 – 6.1.12. The end-point relative permeabilities to water and oil are in

Figure 6.1.13.

Graphs of oil recovery, oil cut and average oil saturation from all four floods

are in Figures 6.1.14 – 6.1.16. The initial and residual oil saturations are in

Figure 6.1.17. All four effluent pH histories are in Figure 6.1.18. In all cases

49

the arrival of the LSB at the outlet was signaled by an increase in pH.

Experimental results are available in Table 6.1.4.

Viscosity vs. shear rate at 55ºC for Crude A, HSB and LSB are graphed in

Figures 6.1.19 – 6.1.21, respectively.

HSS and LST – 1 is a piston-like displacement, with most of the ultimate

recovery achieved at breakthrough. In the other three waterfloods

breakthrough occurred sooner but oil production persisted for longer resulting

in a higher ultimate recovery. Contrary to expectation, HSS and LST – 2

produced the lowest residual oil saturation. HSS and LST – 1’s residual oil

saturation was the highest and LSS 1 and 2’s were indistinguishable. Neither

of the LS tertiary injections recovered incremental oil.

The results of the two HSS and LST waterfloods contrast considerably. The

core had never been exposed to LS brine before to HSS and LST – 1, but had

been exposed before HSS and LST – 2. The two LS secondary waterfloods

produced very similar recovery curves and residual oil saturations. The core

had been exposed to LS brine before to both these floods.

50

Generally, end-point water relative permeability decreased during LS

waterfloods, but the reductions were small and permeability was restored by

injecting HSB. krwº was smallest during the first exposure to LSB. End-point

oil relative permeability decreased during aging, decreased further after HSS

and LST – 1 and from then on rose after each subsequent flood.

The considerable contrast between HSS and LST – 1 and 2 and the similarity

between LSS – 1 and 2 suggest that the LS tertiary injection at the end of HSS

and LST – 1 produced an irreversible wettability alteration that persisted

throughout subsequent floods. Researchers must bear this in mind when

making comparisons. Nonetheless, based on the reductions in end-point oil

relative permeability and residual oil saturation, this crude oil/rock/brine

system was more mixed-wet after being exposed to LSB.

This case is a poor candidate for LS EOR. LSS – 1’s ultimate oil recovery was

slightly higher then HSS and LST – 1’s ultimate oil recovery. However 90%

of HSS and LST – 1’s ultimate oil recovery was achieved after only 0.3 pore

volumes while almost 2.4 pore volumes were required to reach the same

recovery during LSS – 1. The tertiary oil production reported by other

researchers16, 25, 36 was never observed.

51

TABLE 6.1.1

Experiment 6.1 core properties

Core Material Berea Sandstone

Dimensions (cm) L = 27.8,

D = 5.0

Bulk Volume (ml) 545.6

Tracer-Measured Pore Volume (ml) 119.4

Porosity (%) 21.9

Nitrogen Permeability (md) 615

Brine Permeability (md) 471

52

TABLE 6.1.2

Experiment 6.2 fluid properties

HSB Concentration (g/L)

24.19 NaCl, 6.18 CaCl2,

0.14 Na2S2O4

HSB Viscosity (cp) 0.47

LSB Concentration (g/L)

0.79 NaCl, 0.21 CaCl2,

0.14 Na2S2O4

LSB Viscosity (cp) 0.45

Crude Oil Crude A

Crude Oil Viscosity (cp) 7.93

Temperature (ºC) 55

53

TABLE 6.1.3

Experiment 6.1 conditions

Injection

Rate (ft/day)

Pressure Drop (psi)

Pore Volumes Injected

Temperature (ºC)

Aging Time (days)

Brine Permeability 48.6 1.5 5.6 55

Pre-age oil flood 25.2 36.0 3.7 55

Age 75 2.2

Oil Flood - 1 20.3 36.7 2.0 55

HSS Waterflood - 1 2.0 1.1 3.2 55

LST Waterflood - 1 2.0 1.2 2.9 55

Oil Flood - 2 12.2 36.1 3.0 55

LSS Waterflood - 1 2.0 1.0 5.0 55

Oil Flood - 3 14.3 35.0 2.3 55

HSS Waterflood - 2 2.0 1.0 4.0 55

LST Waterflood - 2 2.0 1.0 3.0 55

Oil Flood - 8 16.6 36.1 2.2 55

LS Waterflood - 2 2.0 1.1 4.0 55

54

TABLE 6.1.4

Experiment 6.1 results

Final So kro krw Breakthrough

Recovery (OOIP)

Final Recovery (OOIP)

Pre-age oil flood 0.732 0.371

Oil Flood - 1 0.747 0.293

HSS Waterflood - 1 0.426 0.060 0.327 0.430

LST Waterflood - 1 0.426 0.052 0.000 0.000

Oil Flood - 2 0.734 0.179

LSS Waterflood - 1 0.402 0.064 0.127 0.453

Oil Flood - 3 0.758 0.216

HSS Waterflood - 2 0.397 0.067 0.289 0.477

LST Waterflood - 2 0.397 0.058 0.000 0.000

Oil Flood - 8 0.750 0.244

LS Waterflood - 2 0.419 0.056 0.087 0.441

55

Figure 6.1.1. Experimental procedure

HSS waterflood - 1

Brine permeability

Oil flood - 1

Pre-age oil flood

2 day age

Oil flood - 2

LSS waterflood - 1

HS brine restoration

Oil flood - 3

Oil flood - 4

LSS waterflood - 2


PV Tracer

LST waterflood - 2

LST waterflood - 1


HSS waterflood - 2

56

00.10.20.30.40.50.60.70.80.9

1

0 20 40 60 80 100 120 140 160 180

Volume Injected (ml)

Nor

mal

ized

Con

duct

ivity

Figure 6.1.2. Effluent conductivity history

0.0

0.5

1.0

1.5

2.0

2.5

3.0

0 1 2 3 4Pore Volumes

Pre

ssur

e D

rop

[psi

]

Whole 50 Inlet

Mid 1 Mid 2

Outlet Whole 300

Figure 6.1.3. Brine permeability, pressure drop

57

0

5

10

15

20

25

30

35

40


Pre

ssur

e D

rop

[psi

] Whole 50InletMid 1Mid 2OutletWhole 300

Figure 6.1.4. Pre-age oil flood, pressure drop

0

5

10

15

20

25

30

35

40

0.0 0.5 1.0 1.5 2.0Pore Volumes

Pre

ssur

e D

rop

[psi


Figure 6.1.5. Oil flood – 1, pressure drop

58

0

5

10

15

20

25

30

35

40

2.90 2.95 3.00Pore Volumes

Pre

ssur

e D

rop

[psi



0

5

10

15

20

25

30

35

40

0.0 0.5 1.0 1.5 2.0 2.5Pore Volumes

Pres

sure

Dro

p [p

si]

Whole 50 Inlet

Mid 1 Mid 2

Outlet Whole 300

Figure 6.1.7. Oil flood - 3, pressure drop

59

0

5

10

15

20

25

30

35

40

0.0 0.5 1.0 1.5 2.0 2.5Pore Volumes

Pre

ssur

e D

rop

[psi

]

Whole 50 Inlet

Mid 1 Mid 2

Outlet Whole 300


0

1

2

3

0 1 2 3 4 5 6Pore Volumes

Pre

ssur

e D

rop

[psi

]

Whole 50InletMid 1Mid 2OutletWhole 300Low Salinity Injection Initiated

Figure 6.1.9. HS secondary and LS tertiary – 1, pressure drop

60

0

1

2

3

4

5

0 1 2 3 4 5Pore Volumes

Pre

ssur

e D

rop

[psi

]

Whole 50 Inlet

Mid 1 Mid 2

Outlet Whole 300

Figure 6.1.10. LS secondary – 1, pressure drop

0

1

2

3

4

0 1 2 3 4 5 6 7Pore Volumes

Pre

ssur

e D

rop

[psi

]

Whole 50InletMid 1Mid 2OutletWhole 300Low Salinity Injection Initiated

Figure 6.1.11. HS secondary and LS tertiary – 2, pressure drop

61

0

1

2

3


Pre

ssur

e D

rop

[psi

]

Whole 50 Inlet

Mid 1 Mid 2

Outlet Whole 300

Figure 6.1.12. LS secondary – 2, pressure drop

0.000.050.100.150.200.250.300.350.40

Pre-ag

e oil f

lood

Oil floo

d - 1

HS seco

ndary

- 1

LS te

rtiary

- 1

Oil floo

d 2

LS se

cond

ary - 1

Oil floo

d - 3

HS seco

ndary

- 2

LS te

rtiary

- 2

Oil floo

d - 4

LS Seco

ndary

- 2

kroº

0.000.020.040.060.080.100.120.140.16krwº

kroº

krwº

Figure 6.1.13. End-point relative permeabilities

62

0

0.1

0.2

0.3

0.4

0.5

0.6


Rec

over

y (O

OIP

)

HSS and LST - 1

LSS - 1

HSS and LST - 2

LSS - 2

Figure 6.1.14. Oil recovery

0

0.2

0.4

0.6

0.8

1

0 0.5 1 1.5 2 2.5 3Pore Volumes

Oil

Cut

HSS and LST - 1

LSS - 1

HSS and LST - 2

LSS - 2

Figure 6.1.15. Oil cut

63

0.3

0.4

0.5

0.6

0.7

0.8

0 0.5 1 1.5 2 2.5 3Pore Volumes

Ave

rage

Oil

Sat

urat

ion HSS and LST - 1

LSS - 1HSS and LST - 2LSS - 2

Figure 6.1.16. Average oil saturation

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

HSS and LST - 1 LSS - 1 HSS and LST - 2 LSS - 2

So

Soi

Sor

Figure 6.1.17. Initial and residual oil saturations

64

7

7.5

8

8.5


pHH.S. Secondary & L.S. Tertiary - 1L.S. Secondary - 1H.S. Secondary & L.S. Tertiary - 2L.S. Secondary - 2

Figure 6.1.18. Effluent pH history

0.1

1

10

100

0.01 0.1 1 10 100 1000Shear Rate (sec-1)

Vis

cosi

ty (c

p)

Figure 6.1.19. Crude A viscosity vs. shear rate

65

0.1

1

0.01 0.1 1 10 100 1000

Shear Rate (sec-1)

Vis

cosi

ty (c

p)

Figure 6.1.20. High salinity brine viscosity vs. shear rate

0.1

1

0.01 0.1 1 10 100 1000

Shear Rate (sec-1)

Vis

cosi

ty (c

p)

Figure 6.1.21. Low salinity brine viscosity vs. shear rate

66

6.2 PARALLEL WATERFLOODS IN BEREA CORES

In this experiment high and low salinity waterfloods were conducted in

several similar Berea cores. The objective of this experiment was to evaluate

the effect of injected brine salinity and cation composition on oil recovery

rate, residual oil saturation and relative permeability. Each waterflood was

conducted in a separate core. The procedures prior to each waterflood were

consistent. A total of 5 waterfloods were performed.

Each individual core was cut from the same block of optically homogeneous

Berea. Measured φ, k and Soi values were all very similar implying analogous

pore structure and mineralogy. Properties of the cores are in Table 6.2.1.

A total of five different brines were used. HSB and mixed LSB (MixLSB),

which are identical to HSB and LSB from Experiment 6.1. And, LS brines

composed of NaCl (NaLSB), CaCl2 (CaLSB) and LiCl (LiLSB) were also

used. All the LS brines had nearly equal equivalent-molar salinity. Also, an

oxygen scavenger, sodium dithionite, was included in every brine to simulate

a reservoir’s reduced state. Crude A, the crude used in Experiment 6.1, was

used in Experiment 6.2 as well. Fluid properties are given in Table 6.2.2.

67

The following procedures, described in detail in Chapter 4, were employed in

each Experiment 6.2 coreflood. The cores were encased in epoxy and

permeability to nitrogen gas was measured. The cores were vacuum saturated

with HSB and pore volume was measured gravimetrically. The temperature

was elevated to 55ºC, a HSB brine flood was conducted and permeability was

calculated. Crude A was injected to establish Soi then the saturated cores were

aged for 10 days; temperature remained at 55ºC during aging. After aging a

waterflood was conducted. A diagram of the experimental procedures is in

Figure 6.2.1. Experimental conditions are given in Table 6.2.3.

Flood 1 consisted of a HSB secondary and a MixLSB tertiary waterflood. The

pressure drops during the single phase HSB flood, oil flood and waterflood

are in Figures 6.2.2 – 6.2.4.

Flood 2 consisted of a MixLSB secondary waterflood. The pressure drops

during the single phase HSB flood, oil flood and waterflood are in Figures

6.2.5 – 6.2.7.

Flood 3 consisted of a NaLSB secondary waterflood. The pressure drops


6.2.8 – 6.2.10.

68

Flood 4 consisted of a CaLSB secondary waterflood. The pressure drops


6.2.11 – 6.2.13.

Flood 5 consisted of a LiLSB secondary waterflood. The pressure drops


6.2.14 – 6.2.16.

The end-point relative permeabilities to water and oil are in Figure 6.2.17.

Graphs of oil recovery, oil cut and average oil saturation from all five floods

are in Figures 6.2.18 – 6.2.20. Initial and residual oil saturations are in Figure

6.2.21. All five effluent pH histories are in Figure 6.2.22. The arrival of LSB

at the outlet was signaled by an increase in pH, as in Experiment 6.1.

Experimental results are available in Table 6.2.4.

Viscosity vs. shear rate at 55ºC for Crude A, HSB and MixLSB are graphed in

Figures 6.1.17 – 6.1.19, respectively. MixLSB, NaLSB, CaLSB and LiLSB

were assumed to have equal viscosity.

69

Dramatically different oil recoveries were observed simply by changing the

injected brine’s cation composition. The MixLSB waterflood produced the

best results while the LiLSB waterflood produced the worst. The HSB,

NaLSB and CaLSB waterfloods all produced very similar oil recoveries.

These results clearly demonstrate the importance of cation selection.

Oil recoveries strong sensitivity to the injected brine’s cation composition is

likely the result of cation exchange. According to Lake18, clay particles

possess a negative charge, “which must be countered by cations from the fluid

if the clay is to remain electrically neutral. The bonds between the clay

exchange sites and the cations are chemical, but they are readily reversible.

The relative ease of replacement of one cation by another is

Li+ < Na+ < K+ <Rb+ <Cs+ < Mg+ < Ca2+ < Sr2+ < Ba2+ < H+ ”

The MixLSB waterflood’s recovery was 15% higher then the HSB

waterflood. The NaLSB and CaLSB waterflood’s oil recoveries were very

similar to the HSB waterflood’s oil recovery. The disruption of the clay

particles was minimized during the MixLSB waterflood suggesting that cation

exchange during the NaLSB and CaLSB waterfloods cancelled or disrupted

the mechanism(s) that imparted the oil recovery enhancement observed during

MixLSB.

70

The contrast in oil recoveries between the NaLSB and the LiLSB waterfloods

was especially surprising. These results were expected to be very similar. In

both cases clays originally equilibrated to highly saline Na-Ca brine were

exposed to low salinity Na or Li brine. The clays begrudgingly surrendered

their divalent Ca ions for monovalent Na or Li ions. The Na ions, which

replaced the Ca just slightly more easily, produced dramatically higher oil

recovery. The Li waterflood’s low recovery could be the result of channelized

flow due to a heterogeneous pore structure or micro fractures.

Researchers29 have proposed that LSB strips mixed-wet fines from the pore

walls, liberating trapped oil. Dramatic permeability damage was not observed

during any of the waterfloods; precluding the assumption of major clay

swelling or clay detachment and migration. The improved oil recovery

observed in the MixLSB waterflood, apparently achieved without stripping of

fines, suggests a different mechanism(s) is responsible.

71

TABLE 6.2.1


Flood 1 Core


Dimensions (cm) L = 27.9, D = 5.0


Gravimetric Pore Volume (ml) 115.3

Porosity (%) 21.1



Flood 2 Core





Porosity (%) 19.6



Flood 3 Core



72



Porosity (%) 19.6



Flood 4 Core





Porosity (%) 19.19



Flood 5 Core





Porosity (%) 19.4



73

TABLE 6.2.2


HSB Concentration (g/L)

24.19 NaCl, 6.18 CaCl2,

0.14 Na2S2O4

HSB Viscosity (cp) 0.47

Mixed LSB Concentration (g/L)

0.79 NaCl, 0.21 CaCl2,

0.14 Na2S2O4

Mixed LSB Viscosity (cp) 0.45

Na LSB Concentration (g/L) 1.00 NaCl,

0.14 Na2S2O4

Na LSB Viscosity (cp) 0.45

Ca LSB Concentration (g/L) 1.00 CaCl2,

0.14 Na2S2O4

Ca LSB Viscosity (cp) 0.45

Li LSB Concentration (g/L) 0.73 LiCl,

0.14 Na2S2O4

Li LSB Viscosity (cp) 0.45

Crude Oil Crude A



74

TABLE 6.2.3


Injection

Rate (ft/day)

Pressure Drop (psi)


Temperature (ºC)

Aging Time (days)

Flood 1


Oil flood 21.6 37.3 4.0 55

Age 55 10.0

HSS Waterflood 2.3 1.6 3.5 55

Mixed LST Waterflood 2.3 1.6 3.0 55

Flood 2


Oil flood 22.7 38.9 4.0 55

Age 55 10.0

Mixed LSS Waterflood 2.3 1.5 5.1 55

Flood 3


Oil flood 24.2 39.4 4.0 55

Age 55 10.0

Na LSS Waterflood 2.3 1.5 5.0 55

75

TABLE 6.2.3 continued

Injection

Rate (ft/day)

Pressure Drop (psi)


Temperature (ºC)

Aging Time (days)

Flood 4


Oil flood 18.4 34.9 4.0 55

Age 55 10.0

Ca LSS Waterflood 2.3 1.2 5.0 55

Flood 5


Oil flood 23.1 41.2 4.0 55

Age 55 10.0

Li LSS Waterflood 2.3 1.3 5.0 55

76

TABLE 6.2.4



Recovery (OOIP)


Flood 1

Oil flood 0.736 0.345

HSS Waterflood 0.367 0.052 0.442 0.502

Mixed LST Waterflood 0.367 0.048 0.000 0.000

Flood 2

Oil flood 0.749 0.291

Mixed LSS Waterflood 0.318 0.043 0.392 0.575

Flood 3

Oil flood 0.752 0.352

Na LSS Waterflood 0.376 0.051 0.349 0.500

Flood 4

Oil flood 0.743 0.290

Ca LSS Waterflood 0.381 0.059 0.401 0.487

Flood 5

Oil flood 0.725 0.376

Li LSS Waterflood 0.433 0.066 0.159 0.403

77


0

0.4

0.8

1.2

1.6


Pre

ssur

e D

rop

[psi

]

Whole 50 InletMid 1 Mid 2Oulet

Figure 6.2.2. Flood 1, brine flood pressure drop

HS waterflood

Brine permeability

Oil flood

10 day age

Mixed LS waterflood

Mixed LS waterflood

Na LS waterflood

Ca LS waterflood

Li LS waterflood

Gravimetric PV

78

0

10

20

30

40

50

0 1 2 3 4Pore Volume

Pre

ssur

e D

rop

[psi

]

Whole 50 Inlet Mid 1 Mid 2Outlet

Figure 6.2.3. Flood 1, oil flood pressure drop

0

2

4

6

8

10


Pre

ssur

e D

rop

[psi

] Whole 50InletMid 1Mid 2Outlet

Figure 6.2.4. Flood 1, waterflood pressure drop

79

0

0.5

1

1.5

2

2.5


Pres

sure

Dro

p [p

si]



0

10

20

30

40

50


Pre

ssur

e D

rop

[psi

]

Whole 50 InletMid 1 Mid 2Outlet


80

0

2

4

6

8


Pre

ssur

e D

rop

[psi

] Whole 50 Inlet

Mid 1 Mid 2

Outlet


0

0.4

0.8

1.2

1.6


Pre

ssur

e D

rop

[psi

]



81

0

10

20

30

40

50


Pre

ssur

e D

rop

[psi

]



0

1

2

3

4

5

6


Pre

ssur

e D

rop

[psi

]

Whole 50 InletMid 1 Mid 2Outlet


82

0

0.4

0.8

1.2

1.6


Pres

sure

Dro

p [p

si]



0

10

20

30

40


Pres

sure

Dro

p [p

si]



83

0

2

4

6

8


Pres

sure

Dro

p [p

si]

Whole 50 Inlet

Mid 1 Mid 2

Outlet


0

0.4

0.8

1.2

1.6

2


Pre

ssur

e D

rop

[psi

]

Whole 50 Inlet

Mid 1 Mid 2

Oulet


84

0

10

20

30

40

50


Pre

ssur

e D

rop

[psi

]

Whole 50Inlet Mid 1Mid 2Outlet


0

1

2

3

4

5

6


Pres

sure

Dro

p [p

si] Whole 50 Inlet

Mid 1 Mid 2

Outlet


85

0.0

0.1

0.2

0.3

0.4

HSS andLST

MixLS NaLS CaLS LiLS

kroº

0.00

0.04

0.08

0.12

0.16krwºkroº

krwº (HS)krwº (LS)


0

0.1

0.2

0.3

0.4

0.5

0.6

0.7


Rec

over

y (O

OIP

)

HSS and LST Mixed LSNa LS Ca LSLi LS


86

0

0.2

0.4

0.6

0.8

1

0 0.5 1 1.5 2Pore Volumes

Oil

Cut

HSS and LSTMixed LSNa LSCa LSLi LS


0.3

0.4

0.5

0.6

0.7

0.8


Ave

rage

Oil

Sat

urat

ion HSS and LST

Mixed LSNa LSCa LSLi LS


87

0.00.10.20.30.40.50.60.70.8

HSS andLST

MixLS NaLS CaLS LiLS

So Soi Sor


6.5

7

7.5

8

8.5


pH

HSS and LST Mixed LSNa LS Ca LSLi LS


88

6.3 SERIAL WATERFLOODS IN RESERVOIR B CORE

In this experiment a sequence of high and low salinity secondary waterfloods

were conducted in a single reservoir core. The objective of this experiment

was to evaluate the effect of low salinity injection on oil recovery rate,

residual oil saturation and relative permeability. The waterfloods were

conducted in the same core, serially, to eliminate the possibility that natural

variations between cores were responsible for any contrasts between the high

and low salinity results.

The core consisted of a stack of 5 core plugs. The plugs came from a

consolidated sandstone oil reservoir, henceforth referred to as Reservoir B.

The plugs were ordered by their air permeability, with the most permeable

plug at the inlet and the least at the outlet. The plugs possess a clay wt% of

less then 5 according to XRD analysis performed the field’s operator. Dark

striations were visible with the naked eye; photos of the core plugs are

available in Figure 6.3.1. Properties of the core and the plugs are given in

Tables 6.3.1.

Two brines were used during waterflood experiments. Synthetic Reservoir B

formation brine (SRBFB), with 65,000 ppm TDS, as the high salinity brine

89

and Synthetic lake B water (SLBW), with 200 ppm TDS, as the low salinity

brine. Fluid properties are given in Table 6.3.2.

The core plugs required cleaning upon arrival. The cores were first restored

using an extractor. The extractor reservoir was filled with an azeotropic

mixture of toluene and chloroform. The core plugs were positioned above the

mixture. A heating plate under the extractor boiled the toluene/chloroform

mixture and solvent vapors traveled through the plugs. The vapors condensed

at the top of the extractor and dripped back down into the liquid reservoir. The

plugs were cleaned in the extractor for about a week. Every two days the

solvent was replaced. Initially the 2-day-old solvent was dark when replaced,

but after 4 to 5 days it became very clear. After the extractor restoration the

plugs were placed in a 98ºC oven for about a day.

Next, the plugs were stacked and placed in a core holder then vacuum

saturated with methanol. Then, about 5 pore volumes of toluene were injected.

The effluent toluene was clear after 2 pore volumes of injection. Next about 5

pore volumes of methanol were injected followed by several pore volumes of

compressed air. The plugs were then removed from the core holder and placed

in a 98ºC oven for almost 2 days; the atmospheric boiling point of methanol is

90

64.7ºC. Toluene and methanol were injected using the oil reservoir

arrangement described in Chapter 3.1.3.

After cleaning, Experiment 6.3 preceded much like Experiment 6.1. A

detailed description of each procedure is available in Chapter 4. The plugs

were stacked and confined inside a core holder and permeability to nitrogen

gas was measured. Pore volume was measured with a salinity tracer. The core

was vacuum saturated with tracer brine then several additional pore volumes

of tracer brine were injected. SRBFB was injected, the effluent was sampled

and pore volume and permeability were calculated. Crude B was injected to

establish Soi then the saturated core was aged for 2 days at 68ºC.

Temperature was reduced to room temperature, the approximate temperature

of Reservoir B, and the following floods were conducted:

• Oil flood – 1

• High salinity waterflood – 1 (HS – 1)

• Oil flood – 2

• Low salinity waterflood – 1 (LS – 1)


• Oil flood – 3

91


• Oil flood – 4




Figure 6.3.3 displays the effluent conductivity history. Figure 6.3.4 displays

the pressure drop during the SRBFB flood. Porosity and permeability were

19.1% and 181 md, respectively. The pressure drop across the inlet section,

originally the most permeable section, is anomalously high. The permeability

damage probably occurred during cleaning with toluene and methanol and

unfortunately persists throughout Experiment 6.3.

Five oil floods were conducted. The pressure drops during the oil floods are

displayed in Figures 6.3.5. Four waterfloods were conducted. The pressure

drops during the waterfloods are in Figure 6.3.6 – 6.3.9. The end point relative

permeabilities to water and oil are in Figure 6.3.10.

Graphs of oil recovery, oil cut and average oil saturation from all four floods


92

6.3.14. All four effluent pH histories are in Figure 6.3.15. Experimental

results are available in Table 6.3.4.

Viscosity vs. shear rate at room temperature for Reservoir B crude, SRBFB

and SLBW are graphed in Figures 6.3.16 – 6.3.18, respectively.

All the waterfloods are relatively piston-like displacements with most of the

ultimate recovery achieved at breakthrough. Comparing the recovery curves is

difficult because the initial saturations are different. Nonetheless the first HS

waterflood recovered the largest percentage of original oil in place. The first

low salinity waterflood reduced Sor by 0.9 saturation units however Soi was

4.7 saturation units lower. The second high and low salinity waterfloods

compare in much the same way.

The first low salinity waterflood caused severe permeability damage, reducing

end-point water relative permeability by a factor of 3. The damage was also

permanent as HS – 2 restored krwº to only 56% of the value observed at the

end of HS – 1. The permeability damage was worst during the first lake water

exposure and was less severe during the second lake water exposure.

93

Injecting Lake B water into Reservoir B would be entirely detrimental. No

recovery benefit was observed and the lake water caused severe permeability

damage. The Lake B water was the least saline LSB used in this research.

Based on the results of Experiments 6.1, 6.2 and 6.4 the permeability damage

could be mitigated by increasing the brine’s TDS to above 1,000 ppm.

However, because Reservoir B possessed very little clay, the literature29, 36, 37

suggests that there is limited potential for improved recovery with low salinity

waterflooding.

94

TABLE 6.3.1


Core Material Reservoir B plugs

Plug Number

Porosity

(%) Kair

(mD) Length (cm)

33H 19.4 460 5.4

4H 19.0 427 5.2

21H 16.6 403 5.2

35H 17.8 337 5.6

36H 17.4 278 5.8

Bulk Dimensions

(cm) L = 27.8, D = 3.7

Bulk Volume (ml) 303.7 Tracer Measure

Pore Volume (ml) 58.0

Bulk Porosity (%) 19.1 Nitrogen

Permeability (md) 236 Brine

Permeability (md) 181

95

TABLE 6.3.2


SRBFB Concentration (g/L)

53.50 NaCl, 7.51 CaCl2,

35.73 MgCl2-6H2O

SRBFB Viscosity (cp) 1.06

SLBW Concentration (g/L)

0.04 NaCl, 0.01 KCl,

0.10 CaCl2, 0.16 MgCl2-6H2O

SLBW Viscosity (cp) 1.00

Crude Oil Crude B


Temperature (ºC) ~ 23 (room temperature)

96

TABLE 6.3.3


Injection

Rate (ft/day)

Pressure Drop (psi)


Temperature (ºC)

Aging Time (days)


Pre-age oil flood 50.4 71.2 4.0 23

Age 68 2.1

Oil Flood - 1 29.1 51.1 0.9 23

HS Waterflood - 1 1.5 4.9 3.0 23

Oil Flood - 2 48.9 89.9 3.8 23

LS Waterflood - 1 1.5 14.5 3.0 23

Oil Flood - 3 41.3 82.1 3.9 23

HS Waterflood - 2 1.5 8.7 3.1 23

Oil Flood - 4 41.3 86.6 3.8 23

LS Waterflood - 2 1.5 11.0 3.4 23

97

TABLE 6.3.4



Recovery (OOIP)


Pre-age oil flood 0.543 0.469

Oil Flood - 1 0.559 0.377

HS Waterflood - 1 0.236 0.039 0.564 0.623

Oil Flood - 2 0.512 0.360

LS Waterflood - 1 0.228 0.012 0.522 0.623

Oil Flood - 3 0.434 0.333

HS Waterflood - 2 0.229 0.022 0.485 0.552

Oil Flood - 4 0.424 0.316

LS Waterflood - 2 0.217 0.016 0.488 0.569

98

Figure 6.3.1. Pictures of core plugs


HS waterflood - 1

Brine permeability

Oil flood - 1

Pre-age oil flood

2 day age

Oil flood - 2

LS waterflood - 1

Oil flood - 3

Oil flood - 4

LS waterflood - 2

PV Tracer


HS waterflood - 2

99

0

0.2

0.4

0.6

0.8

1

0 20 40 60 80 100 120 140Volume Injected (ml)

Nor

mal

ized

Con

duta

nce

Figure 6.3.3. Effluent conductivity history

0

2

4

6

8

10


Pre

ssur

e D

rop

[psi

]

Whole 50 Inlet Mid 1Mid 2 Outlet Whole 300

Figure 6.3.4. Brine permeability, pressure drop

100

0

20

40

60

80

100


Pre

ssur

e D

rop

[psi

]

Pre-age oil floodOil flood - 1Oil flood - 2Oil flood - 3Oil flood - 4

Figure 6.3.5. Oil floods, pressure drops

0

1

2

3

4

5

6

0 0.5 1 1.5 2 2.5 3Pore Volumes

Pre

ssur

e D

rop

[psi

]


Figure 6.3.6.High salinity waterflood – 1, pressure drop

101

02468

10121416

0 0.5 1 1.5 2 2.5 3Pore Volumes

Pre

ssur

e D

rop

[psi

]


Figure 6.3.7. Low salinity waterflood – 1, pressure drop

0

2

4

6

8

10

12

0 0.5 1 1.5 2 2.5 3 3.5Pore Volumes

Pre

ssur

e D

rop

[psi

]


Figure 6.3.8. High salinity waterflood – 2, pressure drop

102

0

2

4

6

8

10

12

14

0 0.5 1 1.5 2 2.5 3 3.5Pore Volumes

Pre

ssur

e D

rop

[psi

]



0.00

0.10

0.20

0.30

0.40

0.50

Pre-ag

e oil f

lood

Oil floo

d - 1

HS wate

rflood

- 1

Oil floo

d - 2

LS w

aterflo

od - 1

Oil floo

d - 3

HS wate

rflood

- 2

Oil floo

d - 4

LS w

aterflo

od - 2

kroº

0.00

0.01

0.02

0.03

0.04

0.05krwº

kroº krwº


103

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0 0.5 1 1.5 2 2.5 3 3.5Pore Volumes

Rec

over

y (O

OIP

)

High Salinity - 1Low Salinity - 1High Salinity - 2Low Salinity - 2


0

0.2

0.4

0.6

0.8

1

0 0.2 0.4 0.6 0.8 1Pore Volumes

Oil

Cut



104

0.15

0.25

0.35

0.45

0.55

0.65

0 0.4 0.8 1.2 1.6 2

Pore Volumes

Ave

rage

Oil

Sat

urat

ion High Salinity - 1

Low Salinity - 1High Salinity - 2Low Salinity - 2


0.0

0.1

0.2

0.3

0.4

0.5

0.6

HS - 1 LS - 1 HS - 2 LS - 2

So

SoiSor


105

6.5

6.7

6.9

7.1

7.3

7.5


pH



1

10

100

0.01 0.1 1 10 100Shear Rate (sec-1)

Vis

cosi

ty (c

p)

Figure 6.3.16. Crude B viscosity vs. shear rate

106

0.1

1

10

0.01 0.1 1 10 100Shear Rate (sec-1)

Vis

cosi

ty (c

p)

Figure 6.3.17. SFBRB viscosity vs. shear rate

0.1

1

10

0.01 0.1 1 10 100Shear Rate (sec-1)

Visc

osity

(cp)

Figure 6.3.18. SLBW viscosity vs. shear rate

107

6.4 SERIAL WATERFLOODS IN RESERVOIR C CORE

In this experiment a sequence of high and low salinity secondary waterfloods

were conducted in a single reservoir core. The objective of this experiment

was to evaluate the effect of low salinity injection on recovery rate, residual

oil saturation and relative permeability. The waterfloods were conducted in

the same core, one after another, to eliminate the possibility that natural

variations between cores were responsible for any contrasts between the high

and low salinity results.

The core consisted of a stack of 6 core plugs. The plugs came from an

unconsolidated sandstone oil reservoir, henceforth referred to as Reservoir C.

The plugs were ordered by their air permeability, with the most permeably

plug at the inlet and the least at the outlet. The plugs possess a clay wt% of

about 20 according to XRD analysis performed the field’s operator. The core

looked and felt like a very tightly packed column of medium sand sized grains

and occasional very fine gravel sized grains. The cores were cleaned at an

external core lab. Properties of the core are given in Tables 6.4.1.

Two brines were used during waterflood experiments. Synthetic Reservoir C

formation brine (SRCFB), with 31,000 ppm TDS, as the high salinity brine

108

and Synthetic lake C water (SLCW), with 1075 ppm TDS, as the low salinity

brine. Fluid properties are given in Table 6.4.2.

The following procedures, described in detail in Chapter 4, were employed.

The plugs were stacked and confined inside a core holder and permeability to

nitrogen gas was measured. Pore volume was measured with a salinity tracer.

The core was vacuum saturated with tracer brine then several additional pore

volumes of tracer brine were injected. Temperature was elevated to 85ºC, the

temperature of Reservoir C. SRCFB was injected, the effluent was sampled

and pore volume and permeability were calculated. Crude C was injected to

establish Soi then the saturated core was aged for 25 days at 85ºC.

After aging the following floods were conducted:

• Oil flood – 2


• Oil flood – 3

• 12 hour age

• Oil flood – 4



109

• Oil flood – 5

• 12 hour age

• Oil flood – 6


• Oil flood – 7

• 12 hour age

• Oil flood – 8


Next, another conductivity tracer was conducted to confirm the material

balance oil saturation. SRCFB was again injected and the effluent was

sampled. Then Crude C was injected, Soi was reestablished and the core was

aged for 25 additional days. This was done to determine if the initial, pre-LS

exposure, wettability could be restored by aging. After the second long age the

following floods were conducted:

• Oil flood – 10



• 12 hour age

110






Figure 6.4.2 displays the pore volume tracer effluent conductivity history.

Figure 6.4.3 displays the pressure drop during the single phase brine flood.

Porosity and permeability were 26.8% and 236 md, respectively.

Thirteen oil floods were conducted. Pressure drops during the oil floods are

all displayed in Figures 6.4.4. Six waterfloods were conducted. Pressure drops

during the waterfloods are in Figure 6.4.5 – 6.3.10. End-point relative

permeabilities to water and oil are in Figure 6.3.11.

Graphs of oil recovery, oil cut and average oil saturation from the waterfloods


6.3.15. Effluent pH histories are in Figure 6.3.16.

111

Residual saturation after low salinity waterflood – 2 was confirmed with a

tracer experiment. Figure 6.4.17 displays the Sor tracer effluent conductivity

history. Tracer measured Sor was 0.225. Material balance Sor was .220.

Viscosity vs. shear rate at room temperature for Reservoir C crude, SRCFB

and SLCW are graphed in Figures 6.4.18 – 6.4.20, respectively.

Low salinity waterflood – 1 recovered 14% more oil then high salinity

waterflood – 1. LS – 1 also reduced Sor by 6.5 saturation units, decreased end-

point water relative permeability by 18% and increased end-point oil relative

permeability by 9%.

After the core was exposed to low salinity brine the system’s recovery was no

longer sensitive to injected brine salinity. High and low salinity waterflood –

2 produced very similar oil recoveries. Sor. kroº and krwº were also less

sensitive.

Salinity sensitivity was restored by re-aging the core for 25 days. Low salinity

waterflooding – 3’s oil recovery was 7% higher then high salinity

waterflooding – 3’s. Sor was reduced by 3.0 saturation units, krwº decreased by

8% and kroº increased by 8%.

112

These results suggest a strong relationship between low salinity improved

recovery and wettability alteration. When low salinity improved recovery was

observed water relative permeability increased and oil relative permeability

decreased implying a shift from mix-wet to water-wet wettability. Also,

injecting low salinity brine improved recovery by delaying breakthrough,

suggesting an improvement in displacement stability. Oil displacement

mobility is more favorable if a crude oil/rock/brine system is water-wet.

After the first exposure to low salinity brine the core was no longer sensitive

to injected brine salinity. However, recovery-salinity sensitivity was restored

by re-aging. During the second 25 day age, kro decreased and krw increased,

suggesting a shift toward mix-wetness.

The core was made mixed-wet during the first 25 day age. Then, during the

first low salinity brine exposure, wettability was shifted to water-wet and

recovery was improved. Water-wetness persisted during high and low

waterflood – 2. Therefore low salinity brine produced no benefit because no

wettability alteration was possible. Then a mix-wet state was restored by the

second 25 day age. Following the age, low salinity waterflood – 3 again

shifted the core toward water-wet and improved oil recovery.

113

TABLE 6.4.1


Core Material Reservoir C plugs

Plug Number

Porosity

(%) Kair

(mD) Length (cm)

3-1 26.5 338 4.8

3-2 26.3 379 4.8

3-3 26.7 469 5.0

3-4 27.8 634 5.0

3-5 27.5 665 4.8

3-6 25.1 888 5.1

Bulk Dimensions

(cm) L = 29.3, D = 3.7

Bulk Volume (ml) 322.8 Tracer Measure

Pore Volume (ml) 86.5

Bulk Porosity (%) 26.8 Nitrogen

Permeability (md) 308 Brine

Permeability (md) 236

114

TABLE 6.4.2


SRCFB Concentration (g/L)

28.62 NaCl, 0.65 KCl,

2.71 CaCl2, 3.89 MgCl2-6H2O

SRCFB Viscosity (cp) 0.37 cp

SLCW Concentration (g/L)

0.70 NaCl, 0.21 CaCl2,

0.35 MgCl2-6H2O

SLCW Viscosity (cp) 0.37

Crude Oil Crude C



115

TABLE 6.4.3


Injection

Rate (ft/day)

Pressure Drop (psi)


Temperature (ºC)

Aging Time (days)


Oil Flood - 1 14.8 58.9 3.4 85 Age 85 25.0 Oil Flood - 2 11.9 58.0 1.5 85

HS Waterflood - 1 2.0 3.4 5.7 85

Oil Flood - 3 12.2 57.5 3.4 85 Age 85 0.5 Oil Flood - 4 11.6 57.4 1.4 85 LS Waterflood - 1 2.0 4.2 5.7 85 HS Brine Restoration 16.1 30.7 5.0 85

Oil Flood - 5 13.5 58.4 3.4 85 Age 85 0.5 Oil Flood - 6 13.0 57.9 1.4 85 HS Waterflood - 2 2.0 3.8 5.8 85 Oil Flood - 7 13.4 58.9 3.4 85 Age 85 0.5 Oil Flood - 8 12.4 56.2 2.2 85 LS Waterflood - 2 2.0 3.9 5.5 85 HS Brine Restoration 16.1 29.8 5.0 85

Oil Flood - 9 15.8 70.8 3.8 85 Age 85 25.0 Oil Flood - 10 15.5 74.4 1.3 85

116

`TABLE 6.4.3 continued

Injection

Rate (ft/day)

Pressure Drop (psi)


Temperature (ºC)

Aging Time (days)

HS Waterflood - 3 2.0 3.6 5.9 85 Oil Flood - 11 15.9 76.3 3.8 85 Age 85 0.5 Oil Flood - 12 15.3 75.3 1.4 85 LS Waterflood - 3 2.0 3.9 5.8 85

Oil Flood - 13 16.7 74.0 1.9 85

117

TABLE 6.4.4



Recovery (OOIP)


Oil Flood - 1 0.626 0.350 Oil Flood - 2 0.638 0.286 HS Waterflood - 1 0.284 0.038 0.277 0.555 Oil Flood - 3 0.571 0.296 Oil Flood - 4 0.603 0.281 LS Waterflood - 1 0.220 0.031 0.376 0.634 HS Brine Restoration 0.220 0.034 Oil Flood - 5 0.552 0.322 Oil Flood - 6 0.592 0.313 HS Waterflood - 2 0.222 0.034 0.361 0.625 Oil Flood - 7 0.540 0.315 Oil Flood - 8 0.580 0.307 LS Waterflood - 2 0.220 0.033 0.359 0.622 HS Brine Restoration 0.220 0.035 Oil Flood - 9 0.529 0.310 Oil Flood - 10 0.592 0.289 HS Waterflood - 3 0.246 0.036 0.387 0.584 Oil Flood - 11 0.555 0.291 Oil Flood - 12 0.579 0.283 LS Waterflood - 3 0.216 0.033 0.361 0.627

Oil Flood - 13 0.539 0.315

118


HS waterflood - 1

Brine permeability

Oil flood - 2

12 hour age

Oil flood - 1

25 day age

Oil flood - 3

Oil flood - 4

LS waterflood - 1


12 hour age

Oil flood - 5

Oil flood - 6

HS waterflood - 2

12 hour age

Oil flood - 7

Oil flood - 8

LS waterflood - 1


PV Tracer

So Tracer

Oil flood - 10

Oil flood - 9

25 day age

HS waterflood - 3

Oil flood - 13

Oil flood - 12

Oil flood - 11

12 hour age

LS waterflood - 3

119

00.10.20.30.40.50.60.70.80.9

1

0 20 40 60 80 100 120 140 160 180Volume Injected (ml)

Nor

mal

ized

Con

duct

ivity

Figure 6.4.2. PV Tracer, effluent conductivity history

0

2

4

6

8


Pre

ssur

e D

rop

[psi

]

Whole 50 InletMid1 Mid2Outlet Whole 300

Figure 6.4.3. Single phase brine permeability, pressure drop

120

55

60

65

70

75

80


Pre

ssur

e D

rop

[psi

]

Oil flood - 1 Oil flood - 2 Oil flood - 3 Oil flood - 4Oil flood - 5 Oil flood - 6 Oil flood - 7 Oil flood - 8Oil flood - 9 Oil flood - 10 Oil flood - 11 Oil flood - 12Oil flood - 13

Figure 6.4.4. Oil floods, pressure drops

0

1

2

3

4

5

6

7


Pre

ssur

e D

rop

[psi

]

Whole 50 Inlet

Mid1 Mid2

Outlet Whole 300


121

0

1

2

3

4

5

6


Pre

ssur

e D

rop

[psi

]

Whole 50 Inlet Mid1

Mid2 Outlet Whole 300


0

1

2

3

4

5

6


Pre

ssur

e D

rop

[psi

]

Whole 50 Inlet Mid1



122

0

1

2

3

4

5

6


Pre

ssur

e D

rop

[psi

]

Whole 50 Inlet Mid1



0

1

2

3

4

5


Pre

ssur

e D

rop

[psi

]

Whole 50 Inlet Mid1



123

0

1

2

3

4

5

0 1 2 3 4 5 6

Pore Volum es

Pres

sure

Dro

p [p

si]

Whole 50

Inlet

Mid1

Mid2

Outlet

Whole 300


125

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7


Rec

over

y (O

OIP

)

High Salinity - 1 Low Salinity - 1




0

0.2

0.4

0.6

0.8

1

0 0.25 0.5 0.75 1Pore Volumes

Oil

Cut





126

0.1

0.2

0.3

0.4

0.5

0.6

0.7


Ave

rage

Oil

Sat

urat

ion





0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

HS 1 LS 1 HS 2 LS 2 HS 3 LS 3

So

Soi Sor


127

5.0

5.5

6.0

6.5

7.0

7.5

8.0


pH

High Salinity - 1 Low Salinity - 1High Salinity - 2 Low Salinity - 2High Salinity - 3 Low Salinity - 3


0

0.2

0.4

0.6

0.8

1

30 45 60 75 90 105 120

Volume Injected (ml)

Nor

mal

ized

Con

duct

ivity

Figure 6.4.17. Sor Tracer, effluent conductivity history

128

1

10

1 10 100 1000Shear Rate (sec-1)

Visc

osity

(cp)

Figure 6.4.18. Crude C viscosity vs. shear rate

0.1

1

0.01 0.1 1 10 100Shear Rate (sec-1)

Visc

osity

(cp)

Figure 6.4.19. SFCRB viscosity vs. shear rate

129

0.1

1

0.01 0.1 1 10 100Shear Rate (sec-1)

Vis

cosi

ty (c

p)

Figure 6.4.20. SLCW viscosity vs. shear rate

130

CHAPTER 7

SUMMARY AND CONCLUSIONS

This research effort was undertaken to study the effect of low salinity

waterflooding on recovery rate, residual oil saturation and relative

permeability. Four sets of experiments were performed: Serial floods in Berea

core, Parallel floods in Berea cores, Serial floods in Reservoir B core and

Serial floods in Reservoir C core.

In Experiment 6.1, Serial floods in Berea core, injecting low salinity brine

reduced residual oil saturation by 2.4 saturation units. However oil recovery

was very slow. 90% of the high salinity waterflood’s ultimate oil recovery

was achieved after 0.3 pore volumes while almost 2.4 pore volumes were

required to reach the same oil recovery during the low salinity waterflood.

End-point water relative permeability to low salinity brine was about 10%

lower then for high salinity brine. End-point oil relative permeability

decreased after the core was exposed to low salinity brine.

Experiment 6.2, Parallel floods in Berea cores, demonstrated the importance

of cation selection. Ultimate oil recovery was very similar during the high

salinity, Na-only low salinity and Ca-only low salinity waterfloods. Ultimate

131

recovery was 15% higher during the Na-Ca low salinity waterflood and 20%

lower during the Li-only low salinity waterflood; both relative to the high

salinity waterflood. The improved ultimate recovery observed during the

mixed Na-Ca low salinity waterflood was accompanied by a 17% reduction in

end-point water relative permeability. While in the less effective Li-only low

salinity waterflood the end point water relative permeability increased by

27%. The Na and Li low salinity results were expected to be very similar. The

Li waterflood’s low recovery could be the result of channelized flow because

a heterogeneous pore structure or micro fractures.

In Experiment 6.3, Serial floods in Reservoir B core, high and low salinity

brines produced very similar ultimate oil recovery. The first low salinity

injection produced a massive 68% reduction in end-point water relative

permeability. The end-point oil relative permeability decreased slightly after

the cores exposure to low salinity brine.

In Experiment 6.4, Serial floods in Reservoir C core, the ultimate oil recovery

during the low salinity waterflood was 14% higher then during the high

salinity waterflood. The low salinity end-point water relative permeability

decreased by 18% while end-point oil relative permeability increased by 9%.

Oil recovery was insensitive to brine salinity after the first low salinity

132

injection; however recovery-salinity sensitivity was restored by re-aging.

After re-aging the core, ultimate oil recovery from low salinity waterflooding

was 7% higher then from high salinity waterflooding. In both successful low

salinity waterfloods, improved recovery was achieved by delaying

breakthough.

These results indicate that low salinity improved recovery is a result of a

wettability alteration from mixed-wet to water-wet. This conclusion is

supported by the following observations:

(1) Low salinity brine improved recovery in three cases: the mixed Na-Ca low

salinity waterflood in Experiment 6.2, the first low salinity waterflood in

Experiment 6.4 and the post-re-age low salinity waterflood also in

Experiment 6.4. In all these cases end-point water relative permeability

decreased during the low salinity injection and in Experiment 6.4 end-

point oil relative permeability increased after the low salinity waterflood.

Post waterflood kroº was not measured in Experiment 6.2. In cases where

low salinity injection was detrimental, oil relative permeability decreased

after low salinity exposure.

(2) Injecting low salinity brine produces a dramatic and persistent wettability

alteration. This is clearly evident in Experiment 6.4, where high and low

133

salinity waterfloods – 1 and 3 produced very contrasting recovery

histories; however, the high and low salinity waterfloods – 2 produced

almost exactly the same recovery. A similar alteration is evident in

Experiment 6.1, where the two high salinity waterfloods contrast but the

two low salinity waterfloods do not. The system had never been exposed

to low salinity brine before the first high salinity waterflood but had

before the second high salinity waterflood and both of the low salinity

waterfloods.

(3) The wettability alteration noted in (2) was reversed by extended aging. In

Experiment 6.4, oil recovery’s salinity sensitivity was eliminated after the

first low salinity injection. However, after re-aging the core 25 days, the

high and low salinity waterfloods again produced contrasting oil

recoveries.

(4) Injecting low salinity brine improved oil recovery only in mixed-wet

systems. The crude oil/rock/brine system studied during Experiment 6.3

was the most water-wet because of low clay content, low reservoir

temperature and a short aging time. In this system injecting low salinity

brine had no effect on recovery. Experiment 6.4, which possessed the

most clay rich core, the highest reservoir temperature and the longest

aging time, exhibited the most dramatic low salinity improved recovery.

134

(5) Injecting low salinity brine in Experiments 6.2 and 6.4 improved recovery

by delaying breakthrough, suggesting an improvement in displacement

stability.

Wettability effects the location of fluids within a rock’s pore space. The fluid

location dramatically impacts residual oil saturation and relative permeability.

The literature2, 12, 26 shows that the waterflood residual oil saturation is lowest

when a rock is mixed-wet. However, the mobility ratio is the most favorable

when a rock is water-wet because krw is depressed and kro is increased.

A successful low salinity waterflood leverages the advantage of both water

and mixed-wetness. The low salinity brine induces a wettability alteration

from mixed-wet to water-wet. However this alteration is localized and it is not

instantaneous. It occurs when an individual pore is contacted by low salinity

brine, not before. When low salinity brine invades a mixed-wet pore it first

displaces any oil occupying the center of the pore. The oil film become

unstable when contacted by low salinity brine and the aqueous phase is

allowed to contact the rock surface. As the pore becomes water-wet, the oil

touching the pore wall is also displaced. Also as krw increases and kro

decreases and the displacement becomes more stable, each pore is swept more

135

efficiently and snap off of oil ganglia is delayed. A summary of the

experimental data is in Table 7.1.

Bucklet-Leverett19 theory was used to demonstrate the benefit of low salinity

induced wettability alteration. Experimentally measured end-point relative

permeabilities, initial and residual oil saturations and water and oil viscosity

from Experiment 6.4 were used. Corey water and oil relative permeability

exponents were assumed. This method was also applied to predict high and

low salinity polymer flood performance. Input data is in Table 7.2. Graphs of

relative permeability vs. water saturation, fractional flow vs. water saturation,

oil recovery and oil cut are in Figures 7.1 – 7.4.

Several different mechanisms have been proposed to explain the wettability

alteration.

Lager et al.16 proposed that low salinity induced multi-component ionic

exchange causes a reduction in ion binding between the crude oil and the rock

surface. Oil-rock bond help stabilize the oil films in mix-wet pores but are

removed when contacted by low salinity brine. After the bonds are removed

the oil films become unstable and the brine comes in contact with the rock

surface. This hypothesis is primarily based on an experiment in which a core

136

was repeatedly flooded with NaCl-only brine then oil flooded and aged. After

aging, the core was insensitive to injected brine salinity. It is the authors

understanding that this mechanism implies injecting soft low salinity brine

would maximize oil recovery. This implication is refuted by the results from

Experiment 6.2, Parallel floods in Berea core, and by Zhang et al.37

Tang and Morrow29 hypothesized heavy polar components in the crude oil

adsorb onto fine particles along the pore walls and that these mixed-wet fines

are striped by low salinity brine. This hypothesis is based on the following

observations: a salinity depended recovery requires clay and reactive crude,

salinity dependence increases with increasing clay content, injection of low

salinity brine induces production of fines in the effluent fluid and low salinity

brine dramatically reduces water relative permeability. Dramatic permeability

damage was never observed during any of this work’s successful low salinity

waterfloods precluding the assumption of major clay swelling or clay

detachment and migration. Also, tertiary low salinity waterfloods never

produced incremental oil. Fines were never observed in effluent fluid samples.

And finally, fines detachment and migration is irreversible; however, re-aging

a core exposed and thus desensitized to low salinity brine restored the core

recovery-salinity sensitivity.

137

In almost all of the low salinity EOR literature reviewed in this paper small

core were used. Other researchers16, 25, 29, 36, 37 generally used cores which

were three inches long and one inch in diameter. In this work, cores eleven

inches or longer were used exclusively. Using longer cores decreases oil and

water phase saturation uncertainty because pore volume is larger, reduces the

impact of capillary end effect and allows the measurement of intermediate

(inlet, outlet, etc.) pressure drops. These new results are thus more reliable

than the data reported in the literature on short core plugs that are typically

only 3 inches long. Some of the experiments reported in the literature showed

a significant pressure drop increase where the experiments in longer cores

showed little or none.

More work is required to validate these results. Any attempts to definitively

show the benefit of low salinity waterflooding and to identify the mechanism

responsible will require a great deal more research.

The most important observations of this study are that the beneficial effects of

low salinity brine are observed only in experiments using cores with a high

clay content that have been aged with an active crude oil for a sufficiently

long time to convert them to a mixed-wet state. All of the successful

experiments were done at either 55 or 85 °C. Little additional information can

138

be learned by injecting low salinity brine into a low clay cores at low

temperature like in Experiment 6.3. However, even though the core used in

Experiment 6.3 had little clay, injecting 200 ppm TDS brine caused severe

permeability damage. Low salinity brines containing at least 1,000 ppm TDS

never caused severe permeability damage even if they contained no hard

cations. Also, when investigating low salinity EOR, aging can not be rushed.

The most dramatic result of this work is undoubtedly Experiment 6.4;

however, Experiment 6.2 demonstrated that primarily quartzose Berea, if aged

for at least 10 days, will possess salinity sensitivity.

Several different experiments should be considered in the future. Experiment

6.4 provides valuable insights into low salinity EOR. The reestablishment of

recovery-salinity sensitivity by re-aging highlights the profound importance

wettability. Additional attention to the effects of aging and re-aging is

warranted. However, it is worth noting that Tang and Morrow30 reported more

dramatic wettability alterations when changing temperature then when

changing aging time. Perhaps wettability could be more efficiently controlled

in future experiments by changing the experimental temperature. Preliminary

Buckley-Leverett calculations predict a contrast between high and low salinity

polymer floods. Polymer experiments may help to confirm the proposal that

low salinity waterflooding induces a more favorable displacement mobility.

139

Also, low salinity polymer flooding is attractive because reducing salinity will

increase polymer yield and reduce chemical costs.

140

TABLE 7.1

Review of experimental data

Soi Sor Post-

waterflood kroº

krwº Breakthrough

Recovery (OOIP)


Experiment 6.1

HSS Waterflood - 1 0.747 0.426 0.060 0.327 0.430

LST Waterflood - 1 0.426 0.426 0.179 0.052 0.000 0.000

LSS Waterflood - 1 0.734 0.402 0.216 0.064 0.127 0.453

HSS Waterflood - 2 0.758 0.397 0.067 0.289 0.477

LST Waterflood - 2 0.397 0.397 0.244 0.058 0.000 0.000

LSS Waterflood - 2 0.75 0.419 0.056 0.087 0.441

Experiment 6.2

HSS Waterflood 0.736 0.367 0.052 0.442 0.502

Mixed LST Waterflood 0.367 0.367 0.048 0.000 0.000

Mixed LSS Waterflood 0.749 0.318 0.043 0.392 0.575

Na LSS Waterflood 0.752 0.376 0.051 0.349 0.500

Ca LSS Waterflood 0.743 0.381 0.059 0.401 0.487

Li LSS Waterflood 0.725 0.433 0.066 0.159 0.403

Experiment 6.3

HS Waterflood - 1 0.559 0.236 0.360 0.039 0.564 0.623

LS Waterflood - 1 0.512 0.228 0.333 0.012 0.522 0.623

HS Waterflood - 2 0.434 0.229 0.316 0.022 0.485 0.552

LS Waterflood - 2 0.424 0.217 0.016 0.488 0.569

141

TABLE 7.1 continued

Soi Sor Post-

waterflood kroº

krwº Breakthrough

Recovery (OOIP)


Experiment 6.4

HS Waterflood - 1 0.638 0.284 0.296 0.038 0.277 0.555

LS Waterflood - 1 0.603 0.22 0.322 0.031 0.376 0.634

HS Waterflood - 2 0.592 0.222 0.315 0.034 0.361 0.625

LS Waterflood - 2 0.580 0.220 0.310 0.033 0.359 0.622

HS Waterflood - 3 0.592 0.246 0.291 0.036 0.387 0.584

LS Waterflood - 3 0.579 0.216 0.315 0.033 0.361 0.627

142

TABLE 7.2

Buckley-Leverett input data

High Salinity Waterflood

Low Salinity Waterflood

High Salinity Polymer Flood

Low Salinity Polymer Flood

Irreducible Water Saturation 0.362 0.397 0.362 0.397

Initial Water Saturation 0.362 0.397 0.362 0.397

Residual Oil Saturation 0.284 0.222 0.284 0.222

End Point Oil Relative Permeability

0.296 0.322 0.296 0.322

End Point Water Relative Permeability

0.038 0.031 0.038 0.031

Water Viscosity (cp) 0.37 0.37 10.00 10.00

Oil Viscosity (cp) 8.00 8.00 8.00 8.00

End Point Mobility Ratio 2.78 2.08 0.10 0.08

Oil Relative Permeability Exponent

3 3 3 3

Water Relative Permeability Exponent

4 4 4 4

Permeability Reduction Factor - - 6 6

143

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.35 0.45 0.55 0.65 0.75Water Saturation

Rel

ativ

e P

erm

eabi

lity

HS kroHS krwLS kroLS krw

Figure 7.1. Relative permeability vs. water saturation

0.0

0.2

0.4

0.6

0.8

1.0

0.35 0.40 0.45 0.50 0.55 0.60 0.65 0.70 0.75 0.80

Water Saturation

Frac

tiona

l Flo

w o

f Wat

er HS Water

LS Water

HS Polymer

LS Polymer

Figure 7.2. Fractional flow of water vs. water saturation

144

0.0

0.1

0.2

0.3

0.4

0.0 1.0 2.0 3.0Pore Volumes

Rec

over

y (P

ore

Vol

umes

)

HS Water

LS Water

HS Polymer

LS Polymer

Figure 7.3. Oil recovery

0.0

0.2

0.4

0.6

0.8

1.0

0.0 0.3 0.5 0.8 1.0

Pore Volumes

Oil

Cut

HS Water

LS Water

HS Polymer

LS Polymer

Figure 7.4. Oil cut

145

WORKS CITED

1. Amott, E.: “Observations Relating to Wettability of Porous Rock,” Trans.,

AIME (1959) 216, 156-162.

2. Anderson, G.A.: “Simulation of Chemical Flood Enhanced Oil Recovery

Processes Including the Effects of Reservoir Wettability”. MS Thesis, The

University of Texas at Austin, May 2006

3. Agbalaka, C.C., Abhijit, Y.D., Patil, S.L., Khataniar, S. & Hemsath, J.R.:

“Coreflooding Studies to Evaluate the Impact of Salinity and Wettability on

Oil Recovery Efficiency” Transport in Porous Media (76) 77-94. May 2008.

4. Bernard, G.G.: “Effect of Floodwater Salinity on Recovery of Oil from

Cores Containing Clays” SPE 1725: Los Angeles, California. Oct. 26-27,

1967.

5. Bhuyan, D., “Effect of Wettability on Capillary Desaturation Curves,” M.S.

Thesis, The University of Texas at Austin, 1986.

6. Buckley, S. E. and Leverett, M. C.: “Mechanism of Fluid Displacements in

Sands”, Trans., AIME (1942) 146, 107-116.

7. Chen, J., Hirasaki, G. and Flaum, M.: “Study of Wettability Alteration

From NMR: Effect of OBM on Wettability and NMR Responses,” 8th

International Sympsium on Reservoir Wettability, May 2004.

146

8. Craig, F. F. Jr.: The Reservoir Engineering Aspects of Waterflooding.

Society of Petroleum Engineers of AIME: New York, NY, 1971.

9. Graue, A., Bogno, T., Moe, R.W., Baldwin, B.A., Spinler, E.A., Maloney,

D. and Tobola, D.P.: “Impacts of Wettability on Capillary Pressure and

Relative Permeability”, Society of Core Analysis, 07, 1999.

10. Hamon, G. and Bennes, M.: “Two-Phase Flow Rock Typing: Another

Approach”, Society of Core Analysis, 13, 2003.

11. Jadhunandan, P.P. and Morrow, N.R.: “Effect of Wettability on

Waterflood Recovery for Crude-Oil/Brine/Rock Systems,” SPE Paper 22597,

66th Annual Technical Conference, Dallas, TX October 1991.

12. Jarrell, P.M., Fox, C.E., Stein, M.H., Webb, S.L.: “Pratical Aspects of CO2

Flooding,” Johns, R.T. (editor), Monograph Series, SPE (2002) 22.

13. Jerauld, G.R., Lin, C.Y., Webb, K.J. & Seccombe, J.C.: “Modeling Low-

Salinity Waterflooding” SPE 102239: Sept. 2006.

14. Kamath, Jairam, Meyer, Robert, Nakagawa and Frank: “Understanding

Waterflood Residual Saturation of Four Carbonate Rock Types”, SPE Paper

71505, 2001 Annual Technical Conference, New Orleans, LA October 2001.

15. Klinkenberg, L.J.: “The Permeability of Porous Media to Liquids and

Gases,” Drilling and Production Practises, American Petroleum Institute

(1941) 200.

147

16. Lager, A., Webb, K.J., Black, C.J.J., Singleton, M. & Sorbie, K.S.: “Low

Salinity Recovery – An Experimental Investigation” SCA2006-36: Presented

at the International Symposium of the Society of Core Analysts in Trondheim,

Norway 12-16 Sept. 2006.

17. Lager, A., Webb, K.J., Collins, I.R. & Richmond, D.M.: “LoSalTM

Enhanced Oil Recovery: Evidence of Enhanced Oil Recovery at the Reservoir

Scale” SPE 113976: Apr. 2008.

18. Lake, L. W.: Enhanced Oil Recovery. Prentice-Hall, Inc.: Upper Saddle

River, New Jersey, 1989.

19. Leverett, M. C.: “Capillary Behavior in Porous Solids”, Trans., AIME

(1942) 142, 152-169.

20. Lewis, J. A.: History of Petroleum Engineering, API, Dallas, TX. (1961)

21. Martin, J.C.: “The Effects of Clay on the Displacement of Heavy Oil by

Water” SPE 1411-G: Caracas, Venezuela. Oct. 14-16, 1957.

22. McGuire, P.L., Chatham, J.R., Pahvan, F.K., Sommer, D.M. & Carini

F.H.: “Low Salinity Oil Recovery: An Exciting New EOR Oppurtunity for

Alaska’s North Slope” SPE 93903: Mar. 2005.

23. Morrow, N.R.: “Capillary Pressure Correlations for Uniformly Wetted

Porous Media”, J.Cdn. Pet. Tech. (Oct. – Dec. 1976), 15, No. 4, 49 – 69.

24. Owolabi, O.O. and Watson, R.W.: “Effects of Rock-Pore Characteristics

on Oil Recovery at Breakthrough and Ultimate Oil Recovery in Water-Wet

148

Sandstones,” SPE Paper 26935, Eastern Regional Conference, Pittsburg, PA

November 1993.

25. Pu, H., Xie, X., Yin, P. & Morrow, N.R.: “Application of Coalbed

Methane Water to Oil Recovery by Low Salinity Waterflooding” SPE

113410: Tulsa, Oklahoma. 19-23 Apr. 2008.

26. Salathiel, R.A.: “Oil Recovery by Surface Film Drainage in Mixed-

Wettability Rocks,” JPT, October 1973, pg 1216 – 1224.

27. Sharma, M.M. & Filoco, P.R.: “Effect of Brine Salinity and Crude-Oil

Properties on Oil Recovery and Residual Saturations” SPE 65402: Sept. 2000,

5 (3) 293-300.

28. Skauge, A. and Ottesen, B.: “A Summary of Experimentally Derived

Relative Permeability and Residual Saturation on North Sea Reservoir Cores”,

Society of Core Analysis, 12, 2002.

29. Tang, G.Q. & Morrow N.R.: “Influence of brine composition and fines

migration on crude oil/brine/rock interactions and oil recovery” Journal of

Petroleum Science and Engineering 24 (1999) 99-111.

30. Tang, G.Q. & Morrow, N.R.: “Salinity, Temperature, Oil Composition

and Oil Recovery by Waterflooding” SPE 36680: Nov. 1997, 12 (4) 269-276.

31. Tie, H. and Morrow, N.R.: “Low Flood Rate Residual Saturations in

Carbonate Rocks”, International Petroleum Technology Company, IPCT

10470, November 2005.

149

32. Webb, K.J., Black, C.J.J. & Al-Ajell, H.: “Low Salinity Oil Recovery –

Log-Inject-Log” SPE 81460: Apr. 2003.

33. Welge, H.J.: “A Simplified Method for Computing Oil Recovery by Gas

and Water Drive”, Trans., AIME (1952) 195, 91-98.

34. Willhite, G.P., Waterflooding, Society of Petroleum Engineers, Vol. 3,

Testbook Series, Richardson, TX., 1956.

35. Yildiz, H.O. & Morrow, N.R., 1996: “Effect of Brine Composition on

Recovery of Moutray Crude Oil by Waterflooding” Journal of Petroleum

Science and Engineering 14 (1996) 159-168.

36. Zhang, Y. & Morrow N.R.: “Comparison of Secondary and Tertiary

Recovery With Change in Injection Brine Composition for Crude

Oil/Sandstone Combinations” SPE 99757: Apr. 2006.

37. Zhang, Y., Xie, X. & Morrow, N.R.: “Waterflood Performance by

Injection of Brine With Different Salinity for Reservoir Cores” SPE 109849:

Nov. 2007.

150

VITA

Scott Rivet was born in Austin, Texas on September 17th 1984 to Robert and

Cynthia Rivet. After graduating from Lake Travis High School, he entered

Trinity University. There he received a Bachelor in Science degree in

Engineering Science in May 2007. Scott continued his studies at The

University of Texas, where he received a Master in Science degree in

Petroleum and Geosystems Engineering in December 2009. Scott will begin a

career with Shell in 2010.

Coreflooding Oil Displacements with Low Salinity Brine

Documents

Transcript of Coreflooding Oil Displacements with Low Salinity Brine