experimental studies on polymer and alkaline-surfactant-polymer flooding to improve heavy oil

152 Pages·2015·4.79 MB·English

EXPERIMENTAL STUDIES ON POLYMER AND
ALKALINE-SURFACTANT-POLYMER FLOODING
TO IMPROVE HEAVY OIL RECOVERY

A Thesis
Submitted to the Faculty of Graduate Studies and Research
In Partial Fulfillment of the Requirements
For the Degree of
Master of Applied Science
In
Petroleum Systems Engineering
University of Regina

By
Razieh Solatpour
Regina, Saskatchewan
June 1, 2015

Copyright 2015: Razieh Solatpour
UNIVERSITY OF REGINA

FACULTY OF GRADUATE STUDIES AND RESEARCH

SUPERVISORY AND EXAMINING COMMITTEE

Razieh Solatpour, candidate for the degree of Master of Applied Science in Petroleum
Systems Engineering, has presented a thesis titled, Experimental Studies on Polymer
and Alkaline-Surfactant-Polymer Flooding to Improve Heavy Oil Recovery, in an oral
examination held on April 15, 2015. The following committee members have found the
thesis acceptable in form and content, and that the candidate demonstrated satisfactory
knowledge of the subject material.

External Examiner: Dr. Nader Mobed, Department of Physics

Supervisor: Dr. Farshid Torabi, Petroleum Systems Engineering

Committee Member: Dr. Fanhua Zeng, Petroleum Systems Engineering

Committee Member: Dr. Babak Mehran, Environmental Systems Engineering

Chair of Defense: Dr. Craig Gelowitz, Software Systems Engineering
ABSTRACT
Polymer flooding is considered a non-thermal secondary/tertiary oil recovery
method. Polymer flooding is intended to reach the goal of improving mobility ratio by
injecting long chain polymer molecules with high molecular weights in order to increase the
viscosity of displacing water. Viscous water assists by having a piston like displacement of
heavy oil, which mitigates fingering phenomena to some extent.
This work aims to investigate the potential of highly concentrated polymer solutions
from different polymers, with respect to enhancing heavy oil recovery. This work also
validates the feasibility of combining alkaline-surfactant-based solutions and polymer
flooding, called Alkaline-Surfactant-Polymer (ASP) flooding, to improve the oil recovery
from thin heavy oil reservoirs in Western Canada.
Extensive review on polymer-chemical flooding literature indicated that most of the
researches investigated the mobility ratio aspect of polymer flooding. This study further
investigated polymer and ASP flooding from the application time aspect by applying them
as a secondary and tertiary recovery method. The effects of implementing polymer and ASP
flooding as a secondary/tertiary recovery method have been studied through a series of
carefully designed laboratory experiments.
Nine sets of polymer flooding experiments were conducted using oil-saturated sand-
pack, various concentrations of Flopaam 3530S (0.1, 0.2, and 0.4 wt%), 0.4 wt% Flocomb
3525C, 0.5 wt% Na CO as alkaline, and different surfactants with various concentrations.
2 3
0.1 wt% NaCl solution was used during all of the experiments as brine. The viscosity of the
oil used in this study accurately measured 960 cp at 23°C. All tests were done in similar
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rock/fluid system (similar sand packs and heavy oil samples). During the experiments, data
such as production trends, recovery factors, differential pressure and, injection pressure were
collected to analyze the experiments. Phase behaviour analysis was conducted prior to the
ASP flooding tests.
Although polymer floods generally show a higher recovery factor than water
flooding, there were no significant differences in ultimate oil recoveries with different
polymers which having the same concentration. The results of increasing polymer
concentration on heavy oil recovery were more noticeable in lower polymer concentrations.
Similar to other enhanced heavy oil recovery techniques, polymer flooding is not
always an ideal process as, in some cases, high injection pressures can be encountered in
heavy oil reservoirs. As the oil near the watered-out pathways is contacted by the alkaline-
surfactant, interfacial tension between them is lowered. A lowered interfacial tension fluid
can be displaced by injection of a lower-viscosity polymer, which then leads to improved
heavy oil recovery under more feasible operational conditions. Addition of alkaline and
surfactant to the polymer solution improved recovery factor. Implementing secondary
polymer/ASP flooding showed faster and higher oil recovery.

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ACKNOLEDGMENTS
First and foremost, I would like to express the deepest appreciation to my supervisor,
Dr. Torabi, for providing me with an excellent atmosphere for doing my research. I would
also like to acknowledge him for his financial support. One simply could not wish for a
better or friendlier supervisor.
I would like to thank Mr. Manoochehr Akhlaghinia, for his personal, academic, and
technical support since the start of my studies.
I wish to express my sincere gratitude to Mr. Ryan Wilton for his friendship and
support. He generously shared his knowledge and experience all the way through my
laboratory experiments.

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DEDICATION

To my family, for all the years we shared together.

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TABLE OF CONTENTS
ABSTRACT ........................................................................................................................ I

ACKNOLEDGMENTS .................................................................................................. III

DEDICATION ................................................................................................................ IV

LIST OF TABLES ......................................................................................................... VII

LIST OF FIGURES ..................................................................................................... VIII

NOMENCLATURE ....................................................................................................... XII

SUBSCRIPTS
 ...............................................................................................................................................................
 XII

ABBREVIATIONS
 ......................................................................................................................................................
 XIII

CHAPTER 1:
  INTRODUCTION .................................................................................. 1

1.1
  HEAVY
 OIL
 .......................................................................................................................................................
 1

1.2
  ENHANCED
 OIL
 RECOVERY
 METHODS
 .......................................................................................................
 7

1.3
  WATER
 FLOODING
 .........................................................................................................................................
 9

1.4
  CHEMICAL
 FLOODING
 ..................................................................................................................................
 11

1.5
  POLYMER
 FLOODING
 ...................................................................................................................................
 13

1.6
  ALKALINE
 FLOODING
 ..................................................................................................................................
 14

1.7
  SURFACTANT
 FLOODING
 .............................................................................................................................
 14

1.8
  MICELLAR
 FLOODING
 ..................................................................................................................................
 16

CHAPTER 2:
  LITERATURE REVIEW ................................................................... 17

2.1
  POLYMER
 FLOODING
 ...................................................................................................................................
 17

2.1.1
  Best
 Time
 For
 Polymer
 Flooding
 ...................................................................................................
 19

2.1.2
  Polymer
 Type
 .........................................................................................................................................
 20

2.1.3
  Polymer
 Slug
 Size
 .................................................................................................................................
 23

2.1.4
  Mobility
 Control
 ....................................................................................................................................
 23

2.1.5
  Polymer
 Slug
 Concentration
 ............................................................................................................
 24

2.1.6
  Viscosity
 of
 Polymer
 Slug
 ..................................................................................................................
 25

2.1.7
  Density
 of
 Polymer
 Slug
 .....................................................................................................................
 27

2.1.8
  Reservoir’s
 Salinity
 Effect
 .................................................................................................................
 27

2.1.9
  Pre-­‐flush
 and
 Post
 Flush
 ....................................................................................................................
 28

2.1.10
  Polymer
 Flow
 Behavior
 in
 Porous
 Media
 ...................................................................................
 29

2.1.11
  Advantages
 of
 Polymer
 Flooding
 ...................................................................................................
 39

2.1.12
  Economical
 Point
 of
 View
 .................................................................................................................
 41

2.2
  ALKALINE-­‐SURFACTANT-­‐POLYMER
 (ASP)
 FLOODING
 ........................................................................
 42

2.2.1
  Definition
 .................................................................................................................................................
 42

2.2.2
  ASP
 Flooding
 in
 Canada
 ....................................................................................................................
 44

2.2.3
  ASP
 Mechanism
 .....................................................................................................................................
 45

2.2.4
  Design
 ........................................................................................................................................................
 47

2.2.5
  Screening
 Criteria
 ................................................................................................................................
 48

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2.2.6
  Advantages
 of
 ASP
 Flooding
 ............................................................................................................
 49

2.3
  OBJECTIVES
 ...................................................................................................................................................
 51

CHAPTER 3:
  EXPERIMENTAL SETUP AND PROCEDURES ........................... 52

3.1
  MATERIAL
 .....................................................................................................................................................
 52

3.1.1
  Brine
 ...........................................................................................................................................................
 52

3.1.2
  Polymer
 .....................................................................................................................................................
 52

3.1.3
  Alkaline
 .....................................................................................................................................................
 57

3.1.4
  Surfactant
 Systems
 ..............................................................................................................................
 57

3.1.5
  Oil
 ................................................................................................................................................................
 57

3.2
  1D
 TWO-­‐PHASE
 CORE
 FLOOD
 EXPERIMENTAL
 PROCEDURE
 ..............................................................
 58

3.3
  DIFFERENTIAL
 PRESSURE
 RESPONSE
 MEASUREMENT
 .........................................................................
 64

3.4
  PHASE
 BEHAVIOR
 ANALYSIS
 ......................................................................................................................
 64

CHAPTER 4:
  EXPERIMENTAL RESULTS ............................................................ 68

4.1
  RHEOLOGICAL
 MEASUREMENTS
 OF
 POLYMER
 SOLUTIONS
 .................................................................
 68

4.2
  1D
 TWO-­‐PHASE
 CORE
 FLOODS
 PERFORMANCE
 .....................................................................................
 71

4.3
  WATER
 FLOODING
 (960
 MPA·S
 OIL,
 1
 WT%
 NACL
 BRINE
 SOLUTION)
 ............................................
 73

4.4
  EFFECT
 OF
 POLYMER
 CONCENTRATION
 (960
 CP
 OIL,
 0.4
 WT%,
 0.2
 WT%,
 AND
 0.1
 WT%

FLOPAAM
 3530S
 HPAM)
 .....................................................................................................................................
 76

4.5
  EFFECT
 OF
 POLYMER
 TYPE
 (960
 CP
 OIL,
 0.4
 WT%
 FLOCOMB
 C3525
 HPAM)
 ............................
 86

4.6
  EFFECT
 OF
 ADDING
 ALKALINE
 AND
 SURFACTANT
 TO
 POLYMER
 SOLUTION
 (960
 CP
 OIL,
 0.2

WT%
 FLOPAAM
 3530S
 +
 0.5
 WT%
 NA2CO3
 +
 0.2
 WT%
 SURFACTANT)
 ..................................................
 89

4.7
  ASP
 FLOODING
 AS
 SECONDARY
 RECOVERY
 METHOD
 (960
 CP
 OIL,
 0.2
 WT%
 FLOPAAM
 3530S
 +

0.5
 WT%
 NA2CO3
 +
 0.2
 WT%
 SURFACTANT)
 ..................................................................................................
 93

4.8
  POLYMER
 FLOODING
 AS
 A
 SECONDARY
 RECOVERY
 METHOD
 (960
 CP
 OIL,
 0.4
 WT%
 FLOCOMB

C3525)
 .....................................................................................................................................................................
 96

4.9
  ALKALINE-­‐POLYMER
 FLOODING
 AS
 A
 SECONDARY
 RECOVERY
 METHOD
 (960
 CP
 OIL,
 0.2
 WT%

FLOPAAM
 3530S
 +
 0.5
 WT%
 NA2CO3)
 .............................................................................................................
 99

CHAPTER 5:
  DISCUSSION ..................................................................................... 103

5.1
  CASE
 1
 –
 WATER
 FLOODING
 VS.
 POLYMER
 FLOODING
 AS
 A
 SECONDARY
 AND
 TERTIARY

RECOVERY
 METHOD
 .............................................................................................................................................
 104

5.2
  CASE
 2
 –
 EFFECT
 OF
 POLYMER
 CONCENTRATION
 ON
 HEAVY
 OIL
 RECOVERY
 ..............................
 107

5.3
  CASE
 3
 –
 EFFECT
 OF
 POLYMER
 TYPE
 ON
 HEAVY
 OIL
 RECOVERY
 ....................................................
 110

5.4
  CASE
 4
 –
 POLYMER
 FLOODING
 VS.
 ASP
 FLOODING
 RECOVERY
 METHOD
 ......................................
 112

5.5
  CASE
 5
 –
 ASP
 FLOODING
 AS
 SECONDARY
 AND
 TERTIARY
 RECOVERY
 METHOD
 ..........................
 116

5.6
  CASE
 6
 –
 ASP
 FLOODING
 VS.
 AP
 FLOODING
 RECOVERY
 METHODS
 ................................................
 119

CHAPTER 6:
  CONCLUSIONS AND RECOMMENDATIONS ........................... 122

6.1
  CONCLUSIONS
 .......................................................................................................................................
 122

6.2
  RECOMMENDATIONS
 FOR
 FUTURE
 WORKS
 ...........................................................................
 125

REFERENCES ............................................................................................................... 127

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LIST OF TABLES
Table 1-1: Classification of crude oils to its measured API gravity. ................................... 1
Table 1-2: Heavy oil and bitumen resource in Western Canada. ........................................ 3
Table 2-1: Summary of oil properties screening criteria for chemical EOR methods. ...... 48
Table 2-2: Summary of Reservoir Characteristic screening criteria for chemical EOR
methods. ...................................................................................................................... 49
Table 3-1: List of used polymers and their properties. ...................................................... 54
Table 3-2: RD and Lot number for the surfactants used in this study. .............................. 57
Table 4-1: Viscosities of injected chemicals at 70% Torque. ............................................ 71
Table 4-2: Sand pack properties for each 1D core flood experiments conducted in this
study. .......................................................................................................................... 72

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LIST OF FIGURES
Figure 1-1: Principal heavy oil and bitumen sandstone deposits of Western Canada ......... 2
Figure 1-2: Diagram of Western Canada basin .................................................................... 4
Figure 1-3: Schematic of water flooding method .............................................................. 10
Figure 1-4: Mobility control by polymer flooding. Displacement of water flooding and
polymer flooding. ....................................................................................................... 13
Figure 1-5: Comparison of displacement efficiency by water flooding, surfactant
flooding, and SP flooding ........................................................................................... 15
Figure 2-1: Polyacrylamide and partially hydrolyzed polyacrylamide .............................. 22
Figure 2-2: Schematic of different fluid behaviours. ......................................................... 26
Figure 2-3: Displacement of residual oil in dead end pores by water flooding and polymer
flooding. ...................................................................................................................... 31
Figure 2-4: Residual oil after water flooding and polymer flooding ................................. 31
Figure 2-5: Residual oil saturation comparison in water, polymer, and ASP flooding ..... 50
Figure 3-1: Chemical structure of PAM and HPAM polymer molecules. ........................ 53
Figure 3-2: Schematic of 1D core flood experiments setup. ............................................. 58
Figure 3-3: Photo of 1D core flood experiments setup. ..................................................... 59
Figure 3-4: Swagelok® sand pack holder. 60
Figure 3-5: Prepared surfactant solutions in different concentrations from 0.1 to 0.4 wt%
for each surfactant type. .............................................................................................. 65
Figure 3-6: Prepared surfactant solutions after adding 1 ml oil, unshaken for 24 hours. .. 65
Figure 3-7: Prepared surfactant solutions 3 hours after shaking. ....................................... 66
Figure 3-8: Prepared surfactant solutions 30 hours after shaking (aqueous phase
becoming more cloudy). ............................................................................................. 67
Figure 4-1: Viscosity vs. Torque of 0.4 wt% Flopaam 3530 in 1 wt% brine at 23°C. ...... 68
Figure 4-2: Viscosity vs. Torque of 0.4 wt% Flocomb C3525 in 1 wt% brine at 23°C. ... 69
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