Jamali Thesis 2014

8/18/2019 Jamali Thesis 2014

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Unconsolidated Oil Sands: Vertical Single Well SAGD Optimization

by

Ali Jamali, B.Sc.

A Thesis

In

Petroleum Engineering

Submitted to the Graduate Facultyof Texas Tech University in

Partial Fulfillment of

the Requirements forthe Degree of

MASTER OF SCIENCE

IN

PETROLEUM ENGINEERING

Approved

Mohamed Y. Soliman

Chair of Committee

James Sheng

Amin Ettehadtavakkol

Mehdi Shahri

Mark Sheridan

Dean of the Graduate School

May, 2014


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Copyright 2014, Ali Jamali


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Texas Tech University, Ali Jamali, May 2014

iii

TABLE OF CONTENTS

ACKNOWLEDGMENTS ........................................................................................... ii

ABSTRACT .................................................................................................................. v

LIST OF TABLES ...................................................................................................... vii

LIST OF FIGURES ................................................................................................... viii

1. INTRODUCTION .................................................................................................... 1

1.1. Basic Characteristics of the Athabasca Oil Sands............................................... 2

1.2. Production Techniques ........................................................................................ 3

1.3. Vertical Single Well SAGD ................................................................................ 3

1.4. Issues with Reservoir Geomechanics .................................................................. 6

1.5. Scope and Organization of the Thesis ................................................................. 7

2. CORE ANALYSIS OF ATHABASCA OIL SANDS ............................................. 9

2.1. Grain Size Distribution ..................................................................................... 10 2.1.1. Sample Preparation ............................................................................................... 10 2.1.2. Sieve Analysis ........................................................................................................ 13 2.1.3. Calculations ............................................................................................................ 14 2.1.4. Results ................................................................................................................... 14 2.1.5. Discussion .............................................................................................................. 16 2.1.6. Remarks ................................................................................................................. 17

2.2. Relative Density ................................................................................................ 18 2.2.1. Procedure ............................................................................................................... 18 2.2.2. Calculations ............................................................................................................ 20 2.2.3. Discussion .............................................................................................................. 23

2.2.4. Remarks ................................................................................................................. 24

2.3. Permeability ...................................................................................................... 25 2.3.1. Experimental Setup ................................................................................................ 25 2.3.2. Sample Preparation ............................................................................................... 28 2.3.3. Manometer ............................................................................................................. 29 2.3.4. Procedure ............................................................................................................... 30 2.3.5. Calculations ............................................................................................................ 31 2.3.6. Results ................................................................................................................... 33 2.3.7. Discussion .............................................................................................................. 33

2.4. Bitumen Viscosity and Density ......................................................................... 36 2.4.1. Procedure ............................................................................................................... 36 2.4.2. Calculations ............................................................................................................ 37 2.4.3. Discussion .............................................................................................................. 38 2.4.4. Remarks ................................................................................................................. 39

2.5. Fluid Saturation ................................................................................................. 40 2.5.1. Sample Preparation ............................................................................................... 40 2.5.2. Soxhlet Extractor .................................................................................................... 41 2.5.3. Modified Core Plug ................................................................................................. 42 2.5.4. Procedure ............................................................................................................... 43


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2.5.5. Calculations ............................................................................................................ 44 2.5.6. Discussion .............................................................................................................. 45 2.5.7. Remarks ................................................................................................................. 46

2.6. Liquefaction ...................................................................................................... 46

3. SIMULATION ........................................................................................................ 49

3.1. Thermal Simulator ............................................................................................ 49

3.2. Model ................................................................................................................ 50 3.2.1. Reservoir Properties .............................................................................................. 50 3.2.2. Grid System ........................................................................................................... 50 3.2.3. Grid System Check ................................................................................................ 55 3.2.4. Steam Injection Pressure and Temperature .......................................................... 55

3.3. Sensitivity Analysis ........................................................................................... 60 3.3.1. Number of Inclusions ............................................................................................. 60 3.3.2. Inclusion Width ....................................................................................................... 62 3.3.3. Inclusion Length ..................................................................................................... 65 3.3.4. Steam Injection Rate .............................................................................................. 69 3.3.5. Multi-Stage Injection............................................................................................... 70

3.4. Conclusions ....................................................................................................... 73 3.5. Recommendation for Future Works .................................................................. 74

BIBLIOGRAPHY ...................................................................................................... 76

A. MATLAB M-FILE PROGRAM ....................................................................... 78

B. MESHGEN INPUT FILE .................................................................................. 85

VITA ............................................................................................................................ 86


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ABSTRACT

Several recovery processes have been proposed for heavy oil and oil sands de-

pending on the reservoir and fluid properties, among which steam-assisted gravity

drainage (SAGD) is being widely used. Surface mining is the best approach in very

shallow depths. However, there are hydrocarbon deposits too shallow for SAGD and

too deep for mining which require special techniques to recover the hydrocarbon eco-

nomically. In addition, relatively huge reserves are left behind as stranded reserves.

Those reserves are usually characterized with weak caprock integrity and without

enough pay thickness for SAGD to be economically viable.

This study focuses on a recently developed technique, called Vertical Single

Well SAGD, for enhanced production from oil sands. Sensitivity analysis has been per-

formed, using CMG-STARS, to evaluate the condition that will help achieving high

efficiency in Vertical Single Well SAGD.

This system consists of a vertical well with multiple highly permeable vertical

planes, called inclusions, which are used for steam injection and liquid production pur-

poses. Steam is injected into the upper part of the formation and the drained liquid is

collected at the bottom of the inclusions. Unlike the conventional steam chamber geom-

etry in SAGD processes, steam moves outward from the inclusion faces into the for-

mation and tends to move laterally out and vertically upward over time. Simulation

studies of the system shows that success of such technique depends on the inclusion

dimensions as well as injection rate and pressure. This study investigates the effect of

inclusion dimensions and steam properties on the performance of such a process. Res-

ervoir simulations of realistic reservoir conditions show promising results in terms of

cumulative steam oil ratio (CSOR) and production rate. Peak oil production occurred at

around 100 days from startup and CSOR dropped to under 3.0m3

m3

after 100 days. The

optimum inclusion dimensions and the best injection scenario.


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Furthermore, a brief investigation of rock and fluid properties of Athabasca oil

sands has been performed, with a focus on absolute permeability measurements. An

understanding of the parameters involved in reservoir flow capacity such as permeabil-

ity variation with effective stress and with temperature, is crucial in the development of

a coupled thermal-geomechanics model. This will provide a better prediction of bitumen

production. Changes in stress and deformation caused by fluid injection or production

in unconsolidated sand formations will result in alteration of pore structure and perme-

ability. In this study, steady state technique is implemented to measure absolute perme-

ability of bitumen-free Athabasca sand as a function of effective stress.


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LIST OF TABLES

2.1 List of Standard Sieves Used in this Sieve Analysis ...................................... 13

2.2 Sample Properties............................................................................................ 29

2.3 Calibration Factor “C” for Cannon-Fenske Opaque Viscometers .................. 38

3.1 Reservoir Fluid/Rock Properties of McKay River and Clearwater

Formations or Middle Athabasca McMurray FormationOil Sands ....................................................................................... 51

3.2 Reservoir Fluid/Rock Properties Used in this Study ...................................... 51


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LIST OF FIGURES

1.1 Alberta Map (Alberta Geological Survey) ........................................................ 2

1.2 Vertical Single Well SAGD Completion (Hocking et al., 2012) ...................... 5

1.3 Compressibility vs. Effective Stress (Li et al., 2004) ....................................... 8

2.1 (a) Oil Sands (Left) and (b) Clean Soil after Bitumen Extraction (Right) ...... 12

2.2 Grain Size Distribution of Athabasca Sand .................................................... 15

2.3 Grain Size Distribution of Athabasca McMurray Formation Oil Sands,Oldakowski (1994) ........................................................................ 17

2.4 Bulk Density and Relative Density of Sand as a Function of Porosity ........... 24

2.5 Experimental Setup for Permeability Experiment .......................................... 27

2.6 Manometer Used as Differential Pressure Gauge ........................................... 31

2.7 High Resolution Pressure Difference Indicator on Manometer ...................... 32

2.9 Pore Pressure Changes for a Constant Confining Stress ................................. 34

2.10 Absolute Permeability at 1200 kPa Confining Stress ................................... 35

2.11 Absolute Permeability at 3000, 3500, 4000, 4500 kPa Confining Stress ..... 35

2.12 Dynamic Viscosity of Bitumen as a Function of Temperature ..................... 39

2.13 Density of Bitumen as a Function of Temperature ...................................... 40

2.14 Jacketed Sample (a) before (left) and (b) after Running the Soxhlet

Extractor (right)............................................................................................. 43

2.15 Comparison of Original Sample and Sample with Added Water Drops

under UV Light ....................................................................................... 47

2.16 California Watch Research ........................................................................... 48

3.1 Left: Top View of a Pie Slice (30 degree, 6-inclusion); Right: Cartesianand Cylinderical Grids Demonstration ................................................ 53

3.2 Side View of Spatial Spacing of the Grids in i-Direction (Radial) ................. 53

3.3 Pie Slice Model (top) vs Full Model (bottom) ................................................ 54

3.4 Oil Production Rate Comparison between Pie Slice and Full Model ............. 55

3.5 Steam Phase Diagram ..................................................................................... 56

3.8 Mohr-Circle analysis of Shear Failure at Clearwater Shale (top) andAthabasca McMurray Sand (bottom) (Walters et al., 2012) ......... 59

3.9 Early Oil Production Rate at Different Number of Inclusions ........................ 61

3.10 SOR Performance at Different Number of Inclusions .................................. 61


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3.11 Oil Recovery Factor at Different Number of Inclusions ............................... 62

3.12 Early Oil Production Rate at Different Inclusion Width ............................... 63

3.13 Cumulative SOR at Different Inclusion Width ............................................. 63

3.14 Oil Recovery Factor at Different Inclusion Width ........................................ 64

3.15 Effect of Various Dimensionless Inclusion Length on Oil Recovery after

1 Year of Production ..................................................................... 66

3.16 Recovery Factor Values at Various Dimensionless Inclusion Length .......... 66

3.17 Cross Sectional Temperature Profile after 1 Year of Production ................. 67

3.18 Pressure Profile (left) and Temperature Profile (Right) in a Slice of a

Vertical Single Well SAGD at 1300 kPa Injection Pressure

after 1 Year .................................................................................... 68

3.19 Effect of Injection Rate on Oil Production Rate ........................................... 69

3.20 Oil Production Rate, Constant Injection Pressure ......................................... 72

3.21 Two-Stage Injection Illustration, Varying Injection Pressure....................... 72

3.22 Long-Term Production Rate, Two-Stage Injection ....................................... 73


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CHAPTER I

1. INTRODUCTION

Natural bitumen and extra-heavy oil are characterized by high viscosity and high

density (low API gravity). Major companies have found it desirable to acquire, develop

and produce these resources in increasing volumes, despite their cost and technical chal-

lenges. Natural bitumen and extra heavy oil resources are vast and not a constraint on

their production.

Natural bitumen is reported in 598 deposits in 23 countries commonly in small

deposits at, or near the earth surface. For a long time natural bitumen deposits have been

mined for use as sealants and paving materials. In a few places such deposits are ex-

tremely large, both in areal extent and in resources they contain, most notably those in

northern Alberta, in the western Canada Sedimentary Basin (Survey of Energy Re-

sources, 2010).

The three Alberta oil sands areas (Figure 1.1), Athabasca, Peace River and Cold

Lake together contain 1.73 trillion barrels of discovered bitumen in place (Energy Re-

sources Conservation Board [ERCB], 2009a) representing two-thirds of that in the

world. Outside of Canada 367 natural bitumen deposits are reported in 22 other coun-

tries (Survey of Energy Resources, 2010).

Since heavy oil and bituminous sands contribute to more than 11 percent of total

global oil reserves, recovery processes from Athabasca oil sands have been of great

importance. Recovery processes of such reservoirs do not follow the logic of light oil

recovery because of the high viscosity of the bitumen. Several methods are proposed

for heavy oil recovery, of which steam injection process and generally speaking, thermal

recovery methods seem to be working more effectively, compared to other non-thermal

methods and it is being widely used in Canadian heavy oil reservoirs.


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1.1. Basic Characteristics of the Athabasca Oil Sands

The majority of the oil-rich oil sands are fine-grained to medium-grained dense

sands with small quantities of silt-sized and clay-sized material. The quartz grains are

at least 99% water-wet. The mean bitumen content of the oil-bearing strata is 10% by

total weight, but bitumen content varies from 0% to 18%. The bitumen falls into the

heavy oil category with a specific gravity slightly higher than one, and in-situ viscosities

ranging from 6000 to several million poises. In summary, the Athabasca oil sands is

fine-grained to coarse-grained, water-wet, with significant volumes of viscous intersti-

tial bitumen (Dusseault, 1977).

Figure 1.1 Alberta Map (Alberta Geological Survey)


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1.2. Production Techniques

Raw bitumen in Alberta is produced either by mining or by various in situ tech-

niques using wells to produce bitumen. Bitumen production accounted for 78 percent

of Alberta’s total crude oil and bitumen production in 2012. Bitumen production in-

creased by 4 percent at mining projects and by 17 percent at in situ projects in 2012,

resulting in an overall raw bitumen production increase of 10 percent relative to 2011

(Alberta's Energy Reserves and Supply/Demand Outlook, 2013).

Canada, Venezuela, and the United States are leading producers of unconven-

tional oil reservoirs. In Canada, open-pit mining of shallow oil sands provides approxi-

mately 50% of the nation’s heavy oil production. Open-pit mining has a large environ-

mental impact and can only exploit resources near the surface. In situ production of

heavy oil with sand and thermal production using injected steam provide the remainder

of Canada’s production. In particular, steam assisted gravity drainage (SAGD) produc-

tion is rapidly growing. In Venezuela, cold production with horizontal and multilateral

wells predominates. In the USA, thermal production using steam is the primary produc-

tion means. However, there are several barriers to the rapid growth of heavy oil, extra-

heavy oil, and bitumen production. Nonetheless, there are several commercial in situ

production technologies, and several more in research or pilot phase. Many of the in situ

production methods require an external energy source to heat the heavy oil to reduce itsviscosity (Working Document of the NPC Global Oil and Gas Study).

Finally, Vertical Single Well SAGD is a recently proposed technique with the

potential to enhance heavy oil production. One objective for this thesis is to further study

this technique.

1.3. Vertical Single Well SAGD

Hocking et al. (2008) trialed a new technique including the injection of multi-

azimuth permeable planes in weakly cemented formations, and investigated its applica-

tion to enhanced heavy oil production. They reported that provided using a unique ex-

pandable casing system, it is possible to create repeatable consistent vertical planes with

controlled azimuth.


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This commercial casing system, on mechanical expansion, will split the casing

and cement along pre-aligned vertical planes on six different azimuths. All wings will

open the same amount and remain open. Then, each wing can be stimulated inde-

pendently with a highly viscous fracturing fluid transporting sand proppant. This will

result in formation of highly permeable vertical planes. It is important to keep in mind

that using a dilating casing system, a highly viscous stimulating fluid along with con-

torting the pumping rate, are keys to achieve a controlled and repeatable process. Each

plane was observed to be 40 m in length and 2.5 cm in width. The height of each section

could be up to 10 m. Casing sections are located 5 m apart. Further field trials proved

that multiple vertical propped plains can coalesce, constructing a single, vertical, con-

tinuous, and highly permeable plane in each azimuth. Figure 1.2 shows a schematic of

the final in-placed conductive planes. This method has significant potential to enhance

heavy oil production from soft formations (Hocking et al., 2012).

Upon completion, a vertical Single Well Steam Assisted Gravity Drainage (Ver-

tical Single Well SAGD) injector/producer is proposed. Steam is injected at the top of

the pay through mechanically induced high conductive vertical planes, and liquids are

extracted at the bottom (Figure 1.2). Hocking believes that due to immediate drainage

available from the propped vertical planes, the full gravity drainage height at startup,

and a favorable steam pressure gradient, the well will operates immediately in SAGD

mode and is highly efficient. He defines SAGD mode as the continuous injection of

steam and extraction of liquid. This system will help building a faster steam chamber at

a much lower steam injection pressure. In other word, upon confirming the viability of

such system, faster oil recovery is expected (Hocking et al., 2012).

It is important to have an understanding of the Vertical Single Well SAGD ben-

efits compared to the conventional SAGD. Vertical Single Well SAGD is designed to

provide in-situ recovery of shallow, thin, or stranded, and highly laminated bitumenresources that cannot be developed by SAGD technology. Hocking et al. (2011a);

Hocking et al. (2011b) performed simulation study and concluded that Vertical Single

Well SAGD can outperform conventional SAGD, in variable geologies and also in cases


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where permeable lean zones and barriers will impair SAGD performance, since they

will rapidly halt the vertical growth of the steam chamber. Simulation studies have

showed a higher SOR efficiency for Vertical Single Well SAGD. Because of the high

vertical permeability introduced into the reservoir, steam chamber shape has improved

and a better steam distribution can be provided, resulting in a higher vertical efficiency.

Therefore, the main challenge of SAGD in highly laminated formations (wherek v

k h is

high) is overcome. Finally, because of the immediate drainage, production from Vertical

Single Well SAGD will start from the first day and results in higher Net Present Value.

Figure 1.2 Vertical Single Well SAGD Completion (Hocking et al., 2012)


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1.4. Issues with Reservoir Geomechanics

Reservoir parameters such as compressibility, porosity, and absolute permeabil-

ity are all affected by bulk volume changes. Variations of these parameters due to geo-

mechanical effect, has an impact on reservoir geomechanical simulations of the SAGD

process (Li et al., 2004).

For unconsolidated formations such as oil sands, absolute permeability is far

from being a fixed property. Bulk compressibility is a strong function of pore volume

and pore connectivity which are themselves affected by effective stress. Changes in pore

structure can be attributed to 1- bulk compressibility changes and 2- shear stress induced

volume changes (shear dilation).

During steam injection, changes in the in-situ stresses will occur due to high

pressure steam injected resulting in effective stress reduction and also increase in devi-

atoric stress caused by thermal expansion under lateral confinement. This will result in

shear dilation which will in turn change the pore structure and will induce absolute per-

meability enhancement. Shear dilation is caused by sand grain rotation and displace-

ment and will result in a permanent disruption of the sand structure. Subsequently, po-

rosity and absolute permeability will increase.

On the other hand, bulk compressibility of oil sands is a nonlinear function of

effective stress. In low effective stress ranges, it is also a strong function of effective

stress (Figure 1.3). Unlike shear stress induced volume changes (dilation), bulk com-

pressibility changes will alter porosity without changing grains configuration and their

relative position.

Collins et al. (2002) found the geomechanical enhancement of the SAGD pro-

cess to be significantly beneficial. They believe that this improvement will increase by

operating the SAGD process at higher injection pressures.

Vertical Single Well SAGD is proposed for shallow oil sands formations ranging

from 75 m to 150 m. At this depth, confining stresses are no more than 2.5 MPa (see

Chapter 3 for more details). In this condition even low injection pressures can result in


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very low effective stresses. In other word, bulk compressibility and consequently po-

rosity and absolute permeability of oil sands stimulated by Vertical Single Well SAGD

will be strong functions of injection pressure. Therefore, it is important to investigate

the effect of pore pressure on absolute permeability.

1.5. Scope and Organization of the Thesis

This study is divided into two major parts. Chapter II describes a series of ex-

periments preformed to measure rock and fluid properties of Athabasca oil sands. This

includes grain size distribution, relative density, porosity, water and oil saturation, and

absolute permeability of Athabasca sand along with viscosity and density of bitumen.

Simplified procedures are described and whenever necessary, modifications are sug-

gested for conventional methods and explained in detail. An attempt is made to measure

the absolute permeability of sand (hydraulic conductivity) as a function of confining

stress and pore pressure. Despite a few minor setbacks, the experimental setup showed

reliability and proved to be useful for further studies, but the result are not as compre-

hensive as expected.

Chapter III covers a simulation study performed to assess the performance of

Vertical Single Well SAGD. First, the proposed model is explained in details including

reservoir properties and grid system. Then, sensitivity analysis is performed on physical

dimensions of inclusions including length, height and width. Furthermore, the effect of

steam injection rate and pressure is investigated and multi-stage injection scenarios are

studied. The effect of each parameter on final oil recovery is presented.

Finally, as explained in Chapter III, the validity of the simulations are strongly

contingent to the grid system. A MATLAB m-file program was developed for grid gen-

eration. This program and a sample input file are available in Appendices A and B.


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Figure 1.3 Compressibility vs. Effective Stress (Li et al., 2004)


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CHAPTER II

2. CORE ANALYSIS OF ATHABASCA OIL SANDS

In this chapter, experiments conducted on Athabasca oil sands to evaluate some

of the key rock and fluid properties are presented and explained. Since characteristics

of unconsolidated samples containing such a heavy oil is problematic to measure using

conventional methods, many alterations and simplifications have been made to the con-

ventional methods. The goal of the experiments is to establish modified and well-suited

methods for measuring rock and fluid properties of unconsolidated samples. In most of

these experiments, measured values were compared to results obtained by other inves-

tigators; in case of disagreement between results, the potential explanations are dis-

cussed. Also, a few experimental failures has been encountered which are explained indetail to be avoided in the future.

Most of the recommended practices for core analysis are best suited to consoli-

dated samples. If the samples are poorly consolidated, there are still a few relatively

simple adjustments that may modify conventional methods to make them applicable to

poorly consolidated samples. Conventionally, a cylindrical plug is drilled out of the

cores. This plug is then washed in the Soxhlet extractor to measure fluid saturations.

Afterward, the clean plug which has kept its original shape is placed in cylindrical sam-

ple holders for permeability and porosity measurements.

In case of oil sands, samples are unconsolidated and if the fluid content is

washed out of the sample, the remnants is just loose soil (sand and clay). Therefore,

simple modification of the procedure may not be and utilizing a new methods is essen-

tial. Figure 2.1 shows an oil sands sample of oil sands and the clean soil sample after

getting washed.

For instance, when in loose state, soil permeability can be greater than rock per-meability by three orders of magnitude. The conventional liquid permeameter is not

suitable because the pressure drop is too low (less than 1 psi) to be measurable with

standard pressure gauges. In addition, running the Soxhlet oil extractor will result in


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entire deformation of the sample, so that the bulk volume measurement is problematic.

This attenuates Soxhlet extractor’s applicability in direct measurement of water satura-

tion. Also, soil particles block tubes and syphon and may flow into the flask which

results in inaccuracy.

Because of the abovementioned reasons and after many failed attempts, it was

decided to look at the problem from a different angle so the problem was approached

from a soil mechanics point of view. Therefore, sieve analysis was done on the sample

as the primary task in order to obtain the grain size distribution. Soil characteristics such

as grain size distribution, relative density and hydraulic conductivity were measured and

correlated to porosity, and absolute permeability. Washing the samples will clean clay-

sized minerals out of the sample, but since the clay content of Athabasca sands are re-

ported to be less than 10 percent in Athabasca McMurray formation (Oldakowski,

1996), it can be a reliable assumption to ignore the clay content and expect characteris-

tics close to the real case.

2.1. Grain Size Distribution

This experiment determines the most significant soil characteristics. This is a

routine test in primary steps of any soil mechanics investigation and is explained in most

soil mechanics books and recommended practices. The details of such test is discussed

here.

2.1.1. Sample Preparation

Four random oil sands samples were selected from different depths. The samples

did not have any specific shape. Each sample was placed in the Soxhlet extractor to

extract its oil and water content using toluene. This gave the first clue to show how

highly unconsolidated oil sands samples are. After cleaning bitumen which holds sand

grains together as cohesive agent, oil sands loses its shear resistance becoming a soil.

Then, sand grains were removed from the extractor. At this stage methanol was used to

wash the little streams of oil and eliminate the remaining of the cohesion. Then, the

sample was scattered on a watch glass and placed inside the oven for sufficient time in


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order to let the remaining of the solvent to evaporate. The sample was then weighed and

ready for sieve analysis.

Since insufficient information about the degree of consolidation was available,

Soxhlet extractor was used. It was the first experiment conducted on oil sands and someconsolidations were expected. It was also expected to observe water collected in extrac-

tor’s graduated tube. But, the sample was unconsolidated and sand particles start to flow

into extractor’s syphon and tubes. Also, no water drainage was observed.

All things considered, it is suggested to simply use a heater and flask to wash oil

sands samples. Because the sample contains heavy oil, solvent (toluene) should be reg-

ularly replaced so that all the bitumen can dissolve in the solvent.


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Figure 2.1 (a) Oil Sands (Left) and (b) Clean Soil after Bitumen Extraction (Right)


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2.1.2. Sieve Analysis

The grain size distribution of sandy soils is usually determined by using sieve

analysis. Oven-dry soil with the lumps thoroughly broken down is passed through a

number of sieves. The weight of the dry soil retained on each sieve is determined, and

based on that, the cumulative percent passing a given sieve is determined (Das, 2013).

A sieve analysis is a practice or procedure used to assess the particle size distri-

bution of a granular material. A suitable sieve size for the aggregate should be selected

and placed in order of decreasing size, from top to bottom, in a mechanical sieve shaker.

A pan is placed underneath the nest of sieves to collect the aggregate that passes through

the smallest. The entire nest is then agitated, and the material whose diameter is smaller

than the mesh opening passes through the sieves. After the aggregate reaches the pan,

the amount of material retained in each sieve is weighed.

The standard sieves used in this analysis and its corresponding opening size and

Tyler mesh size are given in Table 2.1. The procedure is as follow:

Gradually pour the sand into the top sieve and shake the sieve column for

sufficient time.

Table 2.1 List of Standard Sieves Used in this Sieve Analysis

Standard SieveNumber

Openings in Microns Tyler Mesh Size

No. 16 1180 14 Mesh

No. 20 850 20 Mesh

No. 30 600 28 Mesh

No. 40 425 35 Mesh

No. 45 355 42 Mesh

No. 60 250 60 Mesh

No. 100 150 100 Mesh

No. 140 105 150 MeshNo. 200 75 200 Mesh

No. 230 62 250 Mesh

No. 325 45 325 Mesh

No. 625 20 625 Mesh

http://en.wikipedia.org/wiki/Particle_size_distributionhttp://en.wikipedia.org/wiki/Particle_size_distributionhttp://en.wikipedia.org/wiki/Particle_size_distributionhttp://en.wikipedia.org/wiki/Particle_size_distribution


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Record the weight of the sand trapped in each sieve. Collect the soil from

each sieve and record the total weight again. This help taking into account

the sample loss during the experiment.

2.1.3. CalculationsThe cumulative weight percent of a soil passing through a given sieve is referred

to as “Percent Finer Than”. A standard graph of grain size distribution plots “Percent

Finer Than” against “Grain Size”. Equation 2.1 can be used for such calculation

Percent Finer Than for Sieve k =Cumulative Mass of Soil Passing Sieve k

Total Mass of Oven-Dry Soil × 100 (2.1)

where k is the index related to the desired.

2.1.4. Results

The result of the sieve analysis for Athabasca sand at various depths is demon-

strated in Figure 2.2. One of the samples had a rather different distribution including

large amounts of soil particles higher than 800 microns. Further examinations showed

that the sample was not washed and shaken enough, which caused small particles to

stick together and create lumps of solid particles. This misleading plot was eliminated.

In general, sieve analysis is aimed at determining some of the basic soil charac-

teristics including the effective size, the uniformity coefficient, and the coefficient of

gradation.

Effective Size – The effective size of a soil is the diameter through which 10%

of the total soil mass is passing and is referred to as D10. An approximate value of 100

microns can be detected from the plot. Other investigators (Hamza, 2012; Oldakowski,

1996) reported values between 80 and 120 microns for Athabasca McMurray formation

oil sands which is in a good agreement with our results.

Uniformity Coefficient – the uniformity coefficient, C u, is defined by Equa-

tion 2.2


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Cu =D60

D10(2.2)

where D60 is the diameter through which 60% of the total soil mass is passing. There-

fore, for these samples

Cu ≈190

100 = 1.9

Coefficient of Gradation/Curvature – the coefficient of gradation/curvature C c

is defined by Equation 2.3

Cc =(D30)

2

(D60) (D10)(2.3)

where D30 is the diameter through which 30% of the total soil mass is passing. Hence,

for these samples

Cc =1502

190 × 100 ≈ 1.2

Figure 2.2 Grain Size Distribution of Athabasca Sand


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Schwartz Uniformity Coefficient – Various authors has suggested different pa-

rameters to describe the degree of formation uniformity. A very common definition,

which is mostly used in proppant and sand pack analysis, is the Uniformity Coefficient

defined by Schwartz. Schwartz Uniformity Coefficient is defined by Equation 2.4

Cµ =D40

D90 (2.4)

where D40 and D90 are the diameter through which 40% and 90% of the total soil mass

is passing. Therefor for these samples

Cµ =170

250 = 0.56

For C µ < 3 the sand is highly uniform and is best described by D10. Although

this categorization is not exact, the Uniformity Coefficient gives a good basis for rela-

tive comparison of the distribution*.

2.1.5. Discussion

Other results for grain size distribution of Athabasca sand are presented in Fig-

ure 2.3 which shows a good agreement with the results of other investigators. The key

goal is to estimate soil characteristics which will help us to make synthetic samples

required for further testing.

“The uniformity coefficient of Athabasca sand is 1.6 and the coefficient of cur-

vature is 0.9. A larger uniformity coefficient means that the grain size distribution is

wider and vice versa. In a Unified Soil Classification System (USCS), well-graded sands

most have a C u value greater than 6 a C c value from 1 to 3. The Athabasca sand is not

well graded, rather as suggested by these numbers and the slope of the grain size distri-

bution curve, it is mostly uniformly-graded sand” (Hamza, 2012).

The result of grain size distribution is important in various aspects. First, if it is

necessary to make samples analogous to Athabasca sand, one can use this distribution

* http://archive.carboceramics.com/English/tools/topical_ref/tr_formation.html


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17

to build those synthetic sand samples with grain size distribution similar to reality. Also,

if fluid properties such as fluid density, viscosity and saturations are known, one can

reconstitute build oil sands samples in order to perform further experiments.

2.1.6. RemarksUsing an automatic mechanical sieve shaker (rather than manually shaking the

sieve column) may reduce the possibility of small grains sticking together and also pre-

vent particles from sticking to sieve openings

According to the AOSTRA Underground Test Facility (UTF), depending on the

depth Athabasca McMurray formation can have high amounts of shale. It can be up to

65% of soft shale and 35% of oil sands in upper levels (Oldakowski, 1996). In these

experiments it was tried to use samples with less visible shale (less than 10%). Accord-ing to ASTM D422-63, the distribution of particle sizes larger than 75 µm (retained on

No. 200 sieve) is determined by sieving, while the distribution of particle sizes smaller

than 75 µm is determined by sedimentation process and using a hydrometer.

Figure 2.3 Grain Size Distribution of Athabasca McMurray Formation Oil Sands,

Oldakowski (1994)


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2.2. Relative Density

Relative density expresses the degree of compactness of a cohesionless soil with

respect to its loosest and densest condition where the sample is prepared using standard

laboratory procedures such as vibration table or free fall through funnel. Relative den-

sity will help evaluating the possibility of initiating liquefaction in oil sands as a fracture

initiation or propagation technique. This will be explained in last section of this chapter.

Maximum and minimum index densities are indications of the void ratio. Also,

in order to calculate maximum and minimum index densities, the specific gravity of

sand grains is required.

Specific gravity of sand and maximum and minimum index densities are essen-

tial before computing relative density. Standard references used for these experiments

are:

ASTM D 854 – Standard Test for Specific Gravity of Soil Solids by Water Pyc-

nometer

ASTM D 4254 – Standard Test Methods for Minimum Index Density and Unit

Weight of Soils and Calculation of Relative Density

ASTM D 4253 – Standard Test Methods for Maximum Index Density and Unit

Weight of Soils Using a Vibratory Table

2.2.1. Procedure

The procedure is as follow:

Pick out about 100 gr of oil sands and wash it with appropriate solvent (tol-

uene). Use a heater if necessary to speed up the process.

Continuously remove the extracted fluid and replace it with fresh solvent as

much as necessary to clean the sample. Since the content is heavy oil, 500mL or more toluene may be required to clean 100 gr sample.


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After cleaning the sample, place it inside the oven until it is completely dried.

The sample is then ready for specific gravity, minimum and maximum index

density measurements.

A standard pycnometer is suggested to measure the specific gravity. If anothercontainer is used, it is recommended to measure its volume by filling it up with gas-free

distilled water. Standard tables offer the density of distilled water at various tempera-

tures which can be later used to calculate the volume of the container.

Continue the procedure as follow:

Fill the pycnometer with distilled water and record its weight, M w,t .

Remove the distilled water and dry the pycnometer. A stream of pressurized

air may help to the process.

Fill approximately one quarter of the pycnometer with the soil and record

the weight, M s.

Fill the pycnometer up to its capacity with distilled water while forming a

slurry of water and soil. Pouring water into the pycnometer at this stage will

cause small bubbles of air to form. To prevent this, try to agitate/shake the

pycnometer while pouring water into it. Also, applying vacuum pump mayhelp to eliminate these air bubbles. An entrapped air removal apparatus such

as vacuum pump is suggested. Record the weight of the pycnometer filled

with soil and water, M ws,t .

The minimum index density of a soil is the soil density at its loosest condition

which is established when the void ratio is maximized. Among many laboratory proce-

dures recommended to maximize void ratio, the preferred method is to carefully pour a

steady stream of oven-dry soil through a funnel into a container of known volume. Forthat purpose, continuously adjust the funnel height in order to maintain a free fall of the

soil of approximately 0.5 inches (Das, 2013). Trim off the excess soil level carefully.


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Try not to disturb the soil since it may cause the rearrangement of the particles. Record

the weight of the container filled with oven-dry soil.

The maximum index density of a soil, on the other hand, is the soil density at its

densest condition which is established when the void ratio is minimized. Vibration is proved to be the most effective method to minimize the void ratio (Casagrande, 1940).

Place a container with known volume on the vibration table and slowly pour the soil

into it while the container is being shaken at a specified frequency for a specified time.

Record the weight of the container filled with oven-dry soil.

2.2.2. Calculations

Specific Gravity – About 130 gr of oil sands was picked from the depth range

of 213 m to 216 m. This sample resulted in 101.79 gr clean sand. Two different contain-ers, including one pycnometer (small) and one Erlenmeyer (large) were used to get a

better accuracy. The volumes of the containers were calibrated using distilled water at

74 °F .

By definition, specific gravity is the mass of the unit volume of the soil divided

by the mass of the same volume of gas-free distilled water at a specified temperature.

This value is useful for calculating the void ratio and also degree of saturation. Specific

gravity of soil can be calculated using equation 2.5

Gs =ρs

ρw,t =

Ms

Mw,t - (Mws,t - Ms)(2.5)

where G s is the soil specific gravity, ρ s is the soil particles density, ρw,t is the density

of water at the test temperature, M s is the mass of the oven-dry soil, Mw,t is the mass

of pycnometer filled with distilled water at the test temperature, and M ws,t is the mass

of pycnometer filled with water and soil at the test temperature. Hence, for the small

container (pycnometer)

Ms = 36.580 - 21.198 = 15.382 gr,


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Gs =15.382

15.382+(49.723-59.359) = 2.677,

and for the large container (Erlenmeyer)

Ms = 157.479 - 73.874 = 83.585gr,

Gs =83.585

83.585+(216.043-268.073) = 2.649,

The density of distilled water at 74 °F is 0.99747 g

mL according to the standard

tables (see ASTM D 854).

Maximum and Minimum Index Density – A standard mold was selected while

its volume was measured using gas-free distilled water. Minimum index density is cal-culated using Equation 2.6

ρdmin =Ms1

Vs(2.6)

where M s1 is the mass of oven-dry soil at its loosest condition and V s is the volume of

the soil (mold). Three measurements were done which resulted in

Measurement 1: ρdmin

=128.00 - 91.04

27.00 = 1.369

Measurement 2: ρdmin =131.50 - 91.04

29.00 = 1.395


46.00 = 1.346

resulting in average value of 1.37.

Maximum index density is defined by Equation 2.7

ρdmax =Ms2

Vs(2.7)


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where M s2 is the mass of oven-dry soil at its densest state. For the same sample three

measurements were done which resulted in


23.2 = 1.592


25.00 = 1.747


47.00 = 1.573

resulting in average value of 1.64. These values are later used for computing maximum

and minimum void ratios.

Maximum and Minimum Void Ratio – The void ratio associated with a given

density of soil, ρ, can be calculated using Equation 2.8

e =ρs

ρ - 1 (2.8)

(e =ρs

ρ - 1 =

ρs - ρ

ρ =

ms

Vs -

mt

Vt

mt

Vt

=

1

Vs -

1

Vt

1

Vt

=Vt - Vs

Vs =

V p

Vs = e).

Maximum and minimum void ratios are associated with minimum and maxi-

mum index densities respectively. Hence

emax =ρs

ρdmin - 1 =

2.65

1.37 - 1 = 0.93

emin =ρs

ρdmax - 1 =

2.65

1.58 - 1 = 0.62

which correspond to the porosities of 0.48 and 0.38 respectively.According to the satu-

ration experiment the value of 0.38 is a good estimation for the porosity. It is important

to keep in mind that these values are measured at lab condition i.e. zero confining stress.


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Depending on the intensity of overburden pressure the void ratio will drop at reservoir

condition.

Relative Density – Relative density expresses the degree of compactness of a

cohesionless soil with respect to its loosest and densest condition and is defined byEquation 2.9

ρD =emax - e

emax - emin (2.9)

where e is any given void ratio and is related to the porosity through Equation 2.10

e =φ

1- φ (2.10)

Assuming a value of 0.35 for porosity at reservoir condition (i.e. higher confining stress)

e =φ

1- φ =

0.35

1 - 0.35 = 0.54

Hence

ρD =emax - e

emax - emin =

0.93 - 0.54

0.93 - 0.6 = 1.25

2.2.3. DiscussionBulk density of a soil sample is a linear function of its porosity and its soil grain

density and can be calculated using Equation 2.11

φ = 1 -ρ b

ρs (2.11)

Also, relative density of a soil sample is a direct function of its porosity and can be

calculated using Equation 2.12

ρD

= a - b φ 1 - φ

(2.12)


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where ρb, ρ s, and ρ D are bulk density, soil grain density, and relative density respec-

tively. Figure 2.4 shows the bulk and relative densities plotted against porosity.

For soil mechanics’ practices, only surface soils are be considered. Since the

overburden pressure is not high at those depths, the value of the void ratio is between

the minimum and maximum index density which results in a relative density between 0

and 1. In this case, due to a high overburden pressure as well as principal horizontal

stresses, the soil will be more compacted compared to surface soils. The assumed value

of 0.35 for porosity results in the void ratio of 0.54 which is very low.

2.2.4. Remarks

Errors regarding the presence of clay minerals, and volume calibrations should

be considered in calculating the specific gravity of sand grains. It is also recommended

that the examiner perform a minimum of three replications to improve measurements’

precision and accuracy.

Figure 2.4 Bulk Density and Relative Density of Sand as a Function of Porosity


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The deaeration process is recommended in the standard method. This process

will help releasing the trapped air inside the distilled water, so volume and weight meas-

urements become more accurate.

The value for porosity (0.35) was selected the literature. A more accurate esti-mation of in-situ porosity is very critical to these calculations.

2.3. Permeability

Permeability is an important parameter in reservoir engineering analysis. Under-

standing the influence that bitumen recovery processes have on permeability is neces-

sary to obtain reasonably accurate predictions of bitumen production rates. The impact

of oil sands compressibility on permeability is better understood and generally applied

in reservoir simulation calculations. In this section, permeability as a function of con-fining stress and pore pressure is investigated.

Various methods in literature have been suggested to measure permeability e.g.

constant head or constant flow rate methods each of them has benefits and shortages.

For this experiment steady state constant head constant flow-rate method was used to

measure absolute permeability (hydraulic conductivity) of Athabasca sand. Although

steady state method is obsolete and time consuming but no other techniques was prac-

tical to be performed for this study.

2.3.1. Experimental Setup

The equipment involved in this experiment are pressure system, flow system,

data acquisition system and electronic instruments, tri-axial load cell and differential

pressure gauge (see Figure 2.5).

Pressure system – including two Quizix pumps, working in constant pressure

mode, one for applying the confining stress and one for maintaining the fluid pressure.

Flow system – including one Quizix pump, working in constant flow rate mode,

in order to maintain steady state flow.


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Data acquisition system and electronic instruments – data from pressure trans-

ducers and electronic thermometer is gathered at compact field point, and sent the host

computer, where data is recorded using LabView.

Tri-axial loading cell – this loading cell is capable of applying radial and axialload on the sample. Identical stresses are applied in radial and axial direction, since axial

and radial stresses are applied by the same pump. A mesh screen is glued to both inlet

and outlet end plugs to prevent the migration of fine particles into the tubing.

Differential pressure gauge – a manometer was designed to serve as a differen-

tial pressure gauge. The details are explained in the following sections.


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Figure 2.5 Experimental Setup for Permeability Experiment


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The core holder is designed for cores 1.5 inches in diameter and less than 2

inches in length. For the purpose of this experiment, appropriate volume of soil should

be poured into the core holder to occupy same space that a consolidated core will oc-cupy. To accurately predict and prepare the required amount of soil, the soil density is

measured based on which appropriate mass of the soil will be poured into the core

holder. The density of soil was measured to be about 1.52 g

cc on vibration table. Based

on that, about 80 gr soil was poured into the core holder. This will provide enough soil

to constitute a 4.5 cm core.

The procedure is as follows:

Insert the outlet end plug in place and screw it. Put the core holder in vertical

position on the vibration table.

Measure the vertical distance between the end cap and the inlet of the core

holder, d1.

Turn on the vibration table and slowly pour the sand into the core holder.

Turn off the vibrator and measure the distance between the upper surface of

the soil and the inlet of the core holder, d2. This difference, d1 - d2 shows

the sample length.

Carefully put the inlet end plug and screw the end cap. The core holder is

ready to get connected to tubing system.

For this experiment the final length of the core was measured to be 4.42 cm. This

length will be used in permeability calculations using Darcy’s law.

Table 2.2 summarize the prepared sample properties. The porosity is calculated

based on soil density and sand grain density which was assumed to be 2.64 gr

cc.


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2.3.3. Manometer

Figure 2.6 shows the manometer that was designed to be used as a high resolu-

tion differential pressure gauge. Distilled water and hydraulic oil are two immiscible

fluids used in this manometer to create a head difference. With the density of 0.83 gr

cc

for hydraulic oil and 1 gr

cc for water, the manometer is capable of measuring 1.66

Pa

mm .

This means that 1 mm of head difference between oil/water interfaces in manometer

central arms corresponds to 1.66 differential pressure. This inherent high resolution of

such manometer will help measuring high permeabilities in the range of 1 Darcy to a

few Darcies. Figure 2.7 shows the manometer pressure indicator.

In order to use this manometer, one should be able to charge the manometer

arms with hydraulic oil and water where each fluid forms a continuous phase. The in-

terface should be clear and no mixing should occur. For this end, the following proce-dure is suggested to charge the manometer:

Turn off all the pumps and close all the valves. Valves I and II are 3-way

valves, connected to atmospheric pressure, core holder and also connected

to each other through the manometer.

Open Valve I to atmospheric pressure. Open Valve II to the core holder out-

let. At this point, if pump II is turned on, distilled water will flow through

the core holder into the manometer (through valve II) and exit the system

through valve I.

Table 2.2 Sample Properties

Length (cm) 4.42

Area (cm2) 11.4

Density (gr/cc) 1.52

Initial Porosity 0.4


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Start pump II and let it flow for a few minutes. Meanwhile, start pump I to

apply appropriate confining stress.

Open valve I to core holder inlet while immediately opening valve II to at-

mospheric pressure. At this point, distilled water is not flowing through thesample, but is flowing through the manometer and exit the manometer

through valve II. Given enough time, all air bubbles will exit the system.

After sufficiently long time, start pump III (operating in constant pressure

mode) and set it to a low pressure and immediately close valve I. At this

point pressure trapped inside the manometer is very close to atmospheric

pressure. Also, after closing valve I and II water flows through the core

holder and exit the system through pump III.

Open Valve III to hydraulic oil. Since the hydraulic oil container is located

at a higher elevation, it has higher pressure than the fluid inside the manom-

eter central arms.

Open Valve I and II to atmospheric pressure and let the oil travels through

the tubing and pushes the water out of the system. Because the interfacial

tension between the tubing and hydraulic oil is higher than interfacial tension

between water and the tubing, oil will smoothly replace the water and the

interface will be clear, if the tubing wall is transparent.

When oil has occupied half the height of the central arms, close Valve II and

open valve I and II to core holder inlet and outlet. At this point, the system

is ready for applying higher pore pressures.

2.3.4. Procedure

After running the manometer, set the confining stress and pore pressure to thedesired values. The rest of the procedure is as follows:

Set the oven temperature to the desired value. The spiral tubing which is

placed before the core holder inlet gives time to distilled water temperature


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to reach equilibrium with the oven temperature before entering the core

holder.

Wait until manometer is stable, i.e. the head difference in central arms is

constant. Record this head difference.

Repeat the process for the next pore pressure. Repeat the process for all de-

sired confining stresses.

2.3.5. Calculations

Assuming Darcian flow, the permeability is calculated using Darcy’s law, ap-

plicable to steady state flow and defined by Equation 2.13

Figure 2.6 Manometer Used as Differential Pressure Gauge


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k =q µ

A Δx

Δp (2.13)

in Metric or Darcy Units. This equation can be rewritten as

k = 1688750 q µ A ΔxΔp

where k is in mD, q is inmL

min, µ is in cP , x is in cm, A is in cm2 and p is in Pa. Consid-

ering 1.66 Pa

mm for manometer reading

k = 1013719q µ

A Δx

h

where h is the differential head in mm.

Figure 2.7 High Resolution Pressure Difference Indicator on Manometer


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2.3.6. Results

Figure 2.8 shows the constant temperature maintained inside the oven during the

experiment. Oven temperature was set to 35 °C . Flow rate was held constant at 0.5 mL

min

.

Figure 2.9 shows pore pressure stages for a constant confining stress. The steady

state condition usually happens after 1 to 2 days for the first data point. For the next data

points a few hours will be enough for the head difference to stabilize. The confining

stress for this case was held at 1200 kPa.

2.3.7. Discussion

Figure 2.10 shows absolute permeability as a function of pore pressure for con-

fining stress of 1200 kPa. Permeability was measured to be is a linear function of pore

pressure with the slope of 0.1 mD

kPa. Figure 2.11 shows the results for another sample at

higher confining stresses. The first curve, as before, shows a linear relation, while the

next three curves do not show a meaningful behavior. This behavior is believed to be

because of the disturbance that occurred to grain particles during the measurements re-

lated to the first confining stress.


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Figure 2.8 Roughly Constant Temperature Maintained inside the Oven

Figure 2.9 Pore Pressure Changes for a Constant Confining Stress


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Figure 2.10 Absolute Permeability at 1200 kPa Confining Stress

Figure 2.11 Absolute Permeability at 3000, 3500, 4000, 4500 kPa Confining Stress


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2.4. Bitumen Viscosity and Density

If the key bitumen properties such as density and viscosity of bitumen are known

along with the grain size distribution, one can build synthetic oil sands sample that acts

quite similarly to the actual ones. This synthetic sample can be used for further investi-

gations. Also, fluid properties are very important parameters used in numerical simula-

tion.

Standard reference used for this experiment is:

ASTM D 2170 – Standard Test Method for Kinematic Viscosity of Asphalts

(Bitumens)

2.4.1. Procedure

Standard viscometers can be used to measure bitumen viscosity. A plot of fluid

viscosity against temperature in a semi-logarithmic scale will result in a rather straight

line. For extremely viscous fluids such as bitumen, it is almost impossible to measure

the fluid viscosity at lower temperatures using conventional viscometers, since bitumen

is almost immobile at lower temperatures including reservoir temperature. Also, it is

difficult to bring reservoir temperature (10 °C ) to the laboratory environment. There-

fore, a semi-log plot of viscosity against temperature is useful to extrapolate viscosity

at low temperatures.

The procedure is as follows:

Use toluene to extract about 50 cc of bitume. Once again, according to the

saturation experiment and in terms of weight percent, oil sands contains

about 81-82% of solids and 18-19% of fluids. Considering water saturation

of 20%, this means that about 300 gr of oil sands is required to extract 50 cc

of bitumen.

Immediately, use a relatively fine sieve to filter small clay and sand particles.

As toluene evaporates, the rest of the fluid becomes more and more viscose

which makes it difficult to pass it through a fine mesh screen.


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Leave the extracted fluid under atmospheric condition and let the toluene to

evaporate. This may take a few days. It is suggested not to put the sample in

oven since it may cause the lighter components to evaporate which will re-

sult in overestimation of viscosity.

When sample weight is stable, pour the fluid into a small beaker. It is rec-

ommended to use a relatively small beaker to get more fluid column. To

mobilize the extremely viscous fluid in the end, we recommend to use a wa-

ter bath or oven at 50 °C .

Cannon-Fenske viscometers are very common and usually available in a variety

of sizes in fluid mechanics labs. The higher the size of the capillary tube the higher the

range of viscosity the viscometer can measure. Cannon-Fenske viscometers are calibrated at two temperatures, usually 40 °C and 100 °C . Viscometer constant is provided

at these two standard temperatures which is available in viscometer calibration sheet.

Cannon-Fenske viscometers with the size of 400 and 450 are recommended to measure

the viscosity of bitumen at 100 °C . Also, Cannon-Fenske viscometers with the size of

600 and 650 are recommended to measure the viscosity of bitumen at 40 °C .

The complete procedure is available in sheets called “Instructions for the use of

The Cannon-Fenske Opaque (Reverse-Flow) Viscometer” which are provided with vis-

cometer and also are available on the internet. Also ASTM D 2170 is a good reference

to check for more details.

Remember to heat up the sample in the oven prior to drawing it into the viscom-

eter. Make sure the entire sample reaches the target temperature uniformly.

2.4.2. Calculations

Cannon-Fenske viscometers number 450 and 600 were used for viscosity at 80

°C and 40 °C respectively. Table 2.3 shows the calibration factors shown on calibration

certificate for each viscometer. Kinematic viscosity is calculated using Equation 2.14.

For the upper and lower bulbs of Cannon-Fenske Opaque viscometer


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ν = Ct (2.14)

where ν is the kinematic viscosity in cSt , C is viscometer constant incSt

s, and t is time

in s. The viscosity was measured at 80 °C and 40 °C for practical reasons. Hence, for

viscometer number 450 at 80 °C

for lower bulb: ν = 2.36 × 208 = 490.88 cSt

for lower bulb: ν = 1.74 × 1007 = 483.72 cSt

And for viscometer number 600 at 40 °C

for lower bulb: ν = 21.01 × 741 = 15568 cSt

for lower bulb: ν = 14.94× 1007 = 15045 cSt

which will result in average values of 487 cSt and 15306 cSt for bitumen kinematic

viscosity at 80 °C and 40 °C respectively.

2.4.3. Discussion

Reynolds (1886) proposed an exponential model for dependency of dynamic

viscosity on temperature. Based on that and by assuming exponential behavior for the

kinematic viscosity for temperatures below 100 °C , one can Equation 2.15 as the gov-

erning equation

ν = ν0e-CT (2.15)

Table 2.3 Calibration Factor “C” for Cannon-Fenske Opaque Viscometers

Viscometer Size at 40 ℃ at 100 ℃

450Lower Bulb: 2.31 cSt/s Lower Bulb: 2.36 cSt/s

Upper Bulb: 1.69 cSt/s Upper Bulb: 1.74 cSt/s

600Lower Bulb: 21.01 cSt/s Lower Bulb: 21.15 cSt/s

Upper Bulb: 14.94 cSt/s Upper Bulb: 15.08 cSt/s


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where ν is the kinematic viscosity of oil in cSt , and T is the temperature in °C. Substi-

tuting measured values for viscosity at 40 °C and 80 °C results in:

ν0 = 481245 cSt, C = 0.08621

°C

assuming the constant density of 1 gr

cc for bitumen, Figure 2.12 shows the dynamic vis-

cosity of bitumen as a function of temperature.

In addition to viscosity, a simple volumetric experiment was conducted to meas-

ure the density of bitumen as a function of temperature. In this experiment, about 6 gr

of bitumen was poured in a graduated cylinder and placed in a hot water bath. The re-

sults are shown in Figure 2.13.

2.4.4. Remarks

Although bitumen contains very low amounts of light components, the presence

of light components may still influence the accuracy of the measured viscosity. Since

Figure 2.12 Dynamic Viscosity of Bitumen as a Function of Temperature


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light components evaporate during the experiment, the measured value is slightly higher

than the reality

There are clay particles that are smaller than the smallest sieve openings. The

presence of these particles also may slightly increase the measured viscosity value. This

also results in overestimation of fluid density since clay minerals have higher density

than bitumen.

More data points increase the accuracy of extrapolation. It is recommended to

measure viscosity at a variety of temperatures.

2.5. Fluid Saturation

There were two attempts to measure the oil and water saturation. Modifications

were made to the conventional Soxhlet method in order to prepare it for unconsolidated

sand samples. Failed and successful attempts are explained in this section.


For an unconsolidated sample, the major challenge is to prepare appropriate

plugs before performing experiments that require a constant shape or a measurable bulk

Figure 2.13 Density of Bitumen as a Function of Temperature


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volume. The shear resistance of oil sands is due to the presence of the bitumen and after

washing the sample, its shear resistance will considerably drop. Simply put, there is no

rock to be characterized; all we have is the loose soil.

First, conventional Soxhlet method was used to measure oil and water saturation.While running Soxhlet, the soil particles occupy the syphon and other tubes of the

Soxhlet extractor. This impedes the functionality of the Soxhlet extractor and makes it

difficult to collect the sand grains afterward. So, it was attempted to find a way using

which oil sands can keep their shape and stay together during the experiment. Modified

core plugs were used which had both successful and unsuccessful aspects.

2.5.2. Soxhlet Extractor

There are a few bottlenecks one may face while using Soxhlet extractor in cor- porate with unconsolidated samples. First, sand grains may flow into the syphon and

other tubes if the sample is abandoned unconfined inside the sample holder. Also, the

bulk volume is not meaningful for an unconsolidated sample because it cannot be easily

measured, it is a function of confining stress, and if the sample is washed, it will com-

pletely lose its shape and consequently its bulk volume.

Furthermore, the longer the cleaning process the higher the possibility of water

entrapment inside the graduated tube after condensation. For unconsolidated samplesthe toluene dissolves the fluid content of the sample before long. This results in for-

mation of an emulsion-like fluid inside the flask. This emulsion consist of the entire oil

and water content of the sample as well as suspended clay particles. Therefore it is not

reasonable to report neither a meaningful water volume nor oil volume. Accordingly, it

is common to measure the saturation of unconsolidated samples as a weight fraction.

This can be later converted to volumetric saturation assuming porosity, water and oil

density are known.


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2.5.3. Modified Core Plug

It is suggested by American Petroleum Institute (1998) to use jacketed samples

in order to keep the shape of the poorly consolidated samples uninterruptable. This

method was examined for unconsolidated samples.

Heat Shrinkable Tube (PTFE) – After a couple of failed attempts it was decided

to create a jacketed sample. The suggested method was to use heat shrinkable tubing

(PTFE) to confine the sample radially and to use screens with appropriate mesh size to

confine the sample axially.

Sufficient amount of oil sands was poured and compressed inside a steel tubing

with inner diameter of 1 inch. The cylindrical plug was then removed from the steel

tubing and put back inside the fridge. Enough time was given until sample recovered its

shear resistance. Then the sample was put inside a heat shrinkable tubing. Using a heat

gun, the heat shrinkable tubing started to shrink until reached the inner diameter of 1

inch. Two screen meshes of different sizes were glued to both sides of the jacketed

sample using appropriate epoxy (Figure 2.14 left).

While running the Soxhlet extractor on this jacketed sample, heat shrinkable

tubing started to shrink when exposed to the heat which was transferred from the vapor-

ized toluene. This caused the confined sample to shrink radially and swell axially and

lose its original shape. Also, the screens on the both sides of the sample were pushed by

swelling oil sands which caused the epoxy not to be able to keep the screens connected

to the sample anymore (Figure 2.14 right). This caused the idea to entirely fail. The

reason might be the size of the heat shrinkable tubing. The final outer diameter of heat

shrinkable tubing should be only slightly smaller than the required plug diameter. This

will prevent any further shrinkage inside the Soxhlet. Nevertheless, the idea looked to

be problematic and is not suggested for unconsolidated samples.


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2.5.4. Procedure

For this experiment, simply extract the bitumen content using sufficient amount

of toluene. A very central feature regarding the fluid saturation experiment is the water

solubility in toluene. The solubility of water in toluene at 25 ºC is 0.033%. If 500 mL of

toluene is used for 100 gr of oil sand, it can dissolve 0.165 gr of water which roughly

corresponds to a water saturation of 100%. This shows the importance of using water

saturated toluene in the experiment. Put the toluene on the heater and add about 0.05%-

by-mass of water to it. Separate the water saturated toluene after it cools down.

The heavy oil content of the oil sands enforces utilizing high amounts of toluene.

First, fill the flask with around 300 mL of toluene. Turn on the heater and wait until the

toluene content of the flask become opaque. This may not take more than 1 hour for the

oil sands samples. Then, remove the flask content into another container and replace it

with clean toluene. Run the experiment with clean toluene as much as necessary until

there is no bitumen remained in sample that is when the toluene stays rather transparent.

Pick a large piece of paper towel and record its weight. Then using a pipet, pick

about 2 percent of the fluid and pour it on the paper towel. After a couple of minutes,

Figure 2.14 Jacketed Sample (a) before (left) and (b) after Running the Soxhlet Ex-

tractor (right)


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toluene and water content of the fluid are vaporized, so that the remainder is only bitu-

men. Use this weight to calculate bitumen content of the entire collected fluid sample.

Put the sand into a beaker and clean it with methanol. Record the weight of the

oven-dry sand.

2.5.5. Calculations

The oil sands sample was taken from the depth of 222.5 – 225.5 m and its weight

was recorded at the beginning

mst = 66.01 g

Four samples were taken from fluid container and were poured on the paper

towels with known weights. The results are as follows:

m p1 = 0.667 g, m pb1 = 0.688 → f b1 =0.688 - 0.667

1 = 0.021

g

ml

m p2 = 1.021 g, m pb2 = 1.036 → f b2 =1.036 - 1.021

1 = 0.015

g

ml

m p3 = 5.351 g, m pb3 = 5.431 → f b3 =5.431 - 5.351

5 = 0.016

g

ml

m p4 = 8.693 g, m pb4 = 8.882 → f b4 =

8.882 - 8.639

10 = 0.019

g

ml

f b =0.021 + 0.015 + 0.016 + 0.019

4 = 0.01775

g

mL → m b = 700 × 0.01775 = 12.425 g

where m p is the weight of the dry paper, m pb is the weight of the paper with bitumen,

and f b is the weight of the bitumen per 1 mL of the fluid. The weight of collected dried

soils was recorded

msd = 53.56 g

Hence, the weight fraction of each component can be calculated. Also, the indirect

measurement of water content is possible


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Figure 2.15 compares the original different samples under UV light. The original

sample does not show any trace of water, rather as suggested Figure 2.15, the fluid in-

dicates a homogeneous solution. Also, a few drops of water corresponding to a water

saturation of approximately 5% was added to the original samples. As you can see, the

presence of this small amount of water is easily visible under the UV light. This proves

that the water saturations in the original samples is close to zero. This claim is rather

valid since all the experiments has been repeated few time to avoid any discrepancies.

Finally, it was concluded that the samples provided by HES may have not been pre-

served carefully before moving to our lab.

2.5.7. Remarks

There is a great error introduced by the water solubility of toluene. It is suggested

to purchase water saturated toluene to use for water saturation measurements to avoid

introducing errors into the measurements.

Bitumen might have some fractions of lighter hydrocarbons that evaporate dur-

ing the experiment which can decrease the calculated viscosity and bitumen saturation

values.

Water weight fraction is measured indirectly which means all other sources of

error are involved in water weight fraction calculations.

2.6. Liquefaction

The liquefaction phenomenon of soil deposits can be described as the reduction

of shear strength due to pore pressure buildup in the soil skeleton. Upon pore pressure

build-up, sand particles move apart from each other. This will cause a reduction in shear

strength. At the onset of initial liquefaction, loose sands will undergo unlimited defor-

mations or flow without significant resistance to deformation. This phenomena is of

interest especially for geotechnical engineers, but in this case, we wanted to evaluate

the possibility of triggering liquefaction in oil sands as a techniques to propagate a ver-

tical plane. If liquefaction is initiated, sand flows without showing any resistance to


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deformation. The best example is the underground mud flow after an Earthquake or

Tsunami.

Among the various factors that determine the possibility of soil liquefaction,

relative density is undoubtedly the most significant of soil characteristics, since it indi-

cates the degree of sand looseness. The looser the sand is, the more susceptible it is to

liquefaction.

There is also ample evidence to show that uniformly graded materials, generally

having a uniformity coefficient smaller than 5, are more susceptible to liquefaction than

well-graded materials and that for uniformly graded soils, fine sands tend to liquefymore easily than coarse sands, gravelly soils, silts or clay. Athabasca sand was measured

to be uniformly graded and susceptible to liquefaction from this point of view. On the

other hand, laboratory test results and field case histories indicate that, for a given soil,

Figure 2.15 Comparison of Original Sample and Sample with Added Water Drops un-

der UV Light


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initial void ratio or relative density is one of the most important factors controlling liq-

uefaction. Liquefaction occurs principally in saturated clean sands and silty sands hav-

ing a relative density less than 50%. The lower limit of relative density beyond which

liquefaction will not occur is about 75%. For more information regarding liquefaction

phenomenon, the readers are referred to Liquefaction Potential of Cohesionless Soil

published by Geotechnical Engineering Bureau.

Relative density of Athabasca sand was measured to be 1.25. Since the upper

limit of relative density for li

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Jamali Thesis 2014