PRESSURE PULSING POTENTIAL DURING WATERFLOODING AND …ourspace.uregina.ca/bitstream/handle/10294/5814/Atamanchuk_Igor... · ii In the first group of experiments, Pressure Pulsing

PRESSURE PULSING POTENTIAL DURING WATERFLOODING AND CO2

FLOODING OF HEAVY OIL RESERVOIRS

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

Igor Atamanchuk

Regina, Saskatchewan

September, 2014

Copyright 2014: Igor Atamanchuk

UNIVERSITY OF REGINA

FACULTY OF GRADUATE STUDIES AND RESEARCH

SUPERVISORY AND EXAMINING COMMITTEE

Igor Atamanchuk, candidate for the degree of Master of Applied Science in Petroleum Systems Engineering, has presented a thesis titled, Pressure Pulsing Potential During Waterflooding and CO2 Flooding of Heavy Oil Reservoirs, in an oral examination held on August 21, 2014. 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. Paitoon Tontiwachwuthikul, Industrial and ProCess Systems Engineering

Chair of Defense: Dr. Raphael Idem, Industrial Systems Engineering *Not present at defense

i

Abstract

The world is facing a challenge of limited sources with respect to hydrocarbons. Society

has become so dependent on oil and natural gas that no one can imagine life without the

resources. Oil and gas deposits are limited and the main portion of conventional

reservoirs is at a late stage of development, hence, the market price for oil and gas is

continuously increasing. The need for development of new technology for oil recovery

from unconventional reservoirs has become a priority.

Canada owns more than 40% of the world’s heavy oil. This means traditional methods of

oil displacement, namely waterflooding or immiscible gas injection, could lead to a very

low recovery factor.

Thermal and chemical impacts on a reservoir are the main methods of increasing sweep

efficiency and recovery factor. Nevertheless, the first method is pricy and the second is

environmentally unfriendly and expensive.

Pressure Pulsing Technology (PPT) does not change the properties of the hydrocarbons

or reservoir, it changes the flow behavior and displacement mechanism. PPT has

traditionally been used during waterflooding, but due to positive results of heavy oil

displacement with CO2 and new GHGs emissions regulations, which provide GHG

credits for CO2 usage in EOR and CO2 underground storage, a decision was made to

implement PPT during carbon dioxide injection. PPT was also implemented in a group of

experiments that covered different WAG processes.

ii

In the first group of experiments, Pressure Pulsing Technology was studied during

waterflooding with different types of oil with a range of PPT parameters. Also, the

impact of PPT on CO2 injections was investigated. In this case, not only PTT properties

were the object of study but the impact of gas injection flow rate was researched.

Logically following water injection and gas injection with PPT was Water Alternative

Gas (WAG) injection with PPT. Several different experiments of the WAG process with

PPT were conducted.

The goal of the second group of experiments, where the micromodel was used, was to

visualize the displacement process in porous media, and to compare fluid flow behavior

in the model, with and without implementing PPT.

iii

Acknowledgements

I would like to express my great appreciation to my supervisor and mentor, Dr. Farshid

Torabi, for his huge support, wisdom advice, rational and effective management and his

academic and field experience. Also, I would like to highlight the friendly and helpful

research group organized by Dr. Torabi.

I want to express my sincere gratitude to the Petroleum Technology Research Centre,

(Regina, Canada) for funding this project and close cooperation.

Also I would like to thank the Faculty of Graduate Studies and Research and Faculty of

Engineering and Applied Science for all the help and support I was provided.

I also wish to say "Thank you" to all my friends and schoolmates who always supported

me with help, ideas and advice when I needed it. They were always ready to share their

knowledge and experience. And lastly, but most importantly - by their own example they

showed me the right way to go.

I would also like to express my special gratitude to my beloved girlfriend Tetiana

Krasilych for her sincere support and understanding, her patience and loyalty during my

entire study.

Exceptional acknowledgement for my loving family (my parents Ihor and Halyna and my

sister Olha) for their unconditional support, vital advice and opportunities.

I want to thank my host family, the wonderful Lorelei Fletcher and Donald Hoffman, for

making me feel like at home thousands of miles from home.

iv

Table of Contents

Abstract ................................................................................................................................ i

Acknowledgements ............................................................................................................ iii

List of Tables ..................................................................................................................... vi

List of Figures .................................................................................................................. viii

List of Abbreviations ....................................................................................................... xiii

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

CHAPTER TWO: LITERATURE REVIEW ..................................................................... 7

2.1 Basic concepts ........................................................................................................... 7

2.2 Laboratory research of pressure pulse technology .................................................. 13

2.3 Field experiments of pressure pulse technology ..................................................... 25

CHAPTER THREE: EXPERIMENTAL EQUIPMENT AND PROCEDURES ............. 46

CHAPTER FOUR: RESULTS AND DISCUSSION ....................................................... 54

4.1 Investigation of Pressure Pulsing Technology impact on waterflooding. Influence

of oil viscosity and pulsing parameters on recovery. .................................................... 54

4.1.1 Implementing Pressure Pulsing Technology during waterflooding in a model

saturated with 13707 cP heavy oil ............................................................................ 54


saturated with 1020 cP heavy oil .............................................................................. 76

4.2 Investigation Pressure Pulsing Technology impact on carbon dioxide (CO2)

injection. Influence of pulsing parameters on recovery. ............................................... 97

v

4.2.1 Carbon dioxide (CO2) injection with following PPT (13707 cP heavy oil). ... 97

4.2.2 Ultra high flow rate carbon dioxide (CO2) injection with following PPT (13707

cP heavy oil). .......................................................................................................... 115

4.3 Investigation Pressure Pulsing Technology impact on WAG displacement ........ 129

4.3.1 Continuous CO2-WAG Flooding ................................................................... 129

4.3.2 Simple CO2-WAG Flooding .......................................................................... 139

4.4. Investigation of heavy oil displacement by Pressure Pulsing Technology using a

micro model. ............................................................................................................... 146

CHAPTER FIVE: CONCLUSIONS AND RECOMMENDATIONS ........................... 161

5.1 Conclusions ........................................................................................................... 161

5.2 Recommendations ................................................................................................. 163

REFERENCES ............................................................................................................... 164

APPENDIX A GAS CONVERSION TABLE .............................................................. 169

vi

List of Tables

Table 2.3.1 – Main field scale experiments and their results............................................ 26

Table 2.3.2 – PPT workovers to march 02, 1999.............................................................. 38

Table 3.1 – Stock-tank oil properties (Unity, Saskatchewan) .......................................... 51

Table 4.1.1.1 – Characteristics of the models used for conventional waterfloods ........... 55

Table 4.1.1.2 – Summary of experiment #1.1................................................................... 59

Table 4.1.1.3 – Summary of experiment #4...................................................................... 63






Table 4.1.2.4 – Summary of experiment #10.................................................................... 90

Table 4.1.2.5 – Summary of experiment #11.................................................................... 94

Table 4.2.1.1 – Summary of experiment #12.................................................................. 104









vii


Table 4.4.1 - Physical and hydraulic properties of micro-model pattern ........................ 147

viii

List of Figures

Figure 1.1 – Oil part of total world energy resources ......................................................... 2

Figure 1.2 - Worldwide distribution of heavy hydrocarbons .............................................. 3

Figure 2.1.1 - Pressure pulsing workover stages ................................................................ 9

Figure 2.1.1 - Pressure pulsing impact on pore throat blockages ..................................... 11

Figure 2.2.1 - Laboratory setup for investigation PPT ..................................................... 15

Figure 2.2.2 - Setup with glass flow model for conducting PPT experiments ................. 16

Figure 2.2.3 - Comparison results of non-pulsing and pulsing waterfloodings in glass

models ............................................................................................................................... 20

Figure 2.3.1 - Well production history of Lindbergh oilfield ........................................... 41

Figure 2.3.2 – Pre- and Post-PPT Chemical treatment production behavior .................... 44

Figure 2.3.3 - Total monthly production behavior for three months before and after PPT

chemical stimulation ......................................................................................................... 45

Figure 3.1- Schematic diagram of the experimental set-up .............................................. 48

Figure 3.2 – Ten – Ten Theory schematic interpretation .................................................. 52

Figure 3.3 – Schematic diagram of the sand pack used in the experiment ....................... 53

Figure 4.1.1.1.—RF vs PV injected during three conventional waterfloods .................... 56

Figure 4.1.1.2—Pressure vs Time during conventional waterflooding ............................ 57

Figure 4.1.1.3—RF vs PV injected during waterflooding with following PPT ............... 60

Figure 4.1.1.4—Oil cut vs PV injected during waterflooding with following PPT ......... 61

Figure 4.1.1.5—Effect of PPT over traditional waterflooding, regarding RF .................. 64

Figure 4.1.1.6—Effect of PPT over traditional waterflooding, regarding oil cut ............. 65

Figure 4.1.1.7—Pressure profile at the inlet of the sandpack during PPT........................ 67

ix

Figure 4.1.1.8—High and low amplitude PPT versus traditional waterflooding, regarding

oil cut ................................................................................................................................ 70

Figure 4.1.1.9—Effect of low and high amplitude PPT over traditional waterflooding,

regarding RF ..................................................................................................................... 71

Figure 4.1.1.10—Pressure profile at the inlet of the sandpack during PPT...................... 72

Figure 4.1.1.11—Relation between RF and different range amplitude PPT and

conventional waterflooding .............................................................................................. 75

Figure 4.1.2.1 — Effect of oil viscosity on oil cut during traditional waterflooding ....... 78

Figure 4.1.2.2— Effect of oil viscosity on recovery factor during traditional

waterflooding .................................................................................................................... 79

Figure 4.1.2.3— Effect of High Amplitude PPT on oil cut versus traditional

waterflooding .................................................................................................................... 83

Figure 4.1.2.4— Effect of High Amplitude PPT on RF versus traditional waterflooding 84

Figure 4.1.2.5— Comparison of Effect of High and Ultra High Amplitude PPT on oil cut

versus traditional waterflooding ....................................................................................... 87

Figure 4.1.2.6— Comparison of Effect of High and Ultra High Amplitude PPT on RF

versus traditional waterflooding ....................................................................................... 88

Figure 4.1.2.7— Comparison of Effect of Low Amplitude PPT over High, Ultra High

Amplitude PPT and traditional waterflooding on RF increase ......................................... 91

Figure 4.1.2.8— Pressure behavior in the sandpack during Low Amplitude PPT

waterflooding. ................................................................................................................... 92

Figure 4.1.2.9— Comparison of Effect of Ultra Low, Low, High, Ultra High Amplitude

PPT and traditional waterflooding on RF ......................................................................... 95

x

Figure 4.2.1.1— Dependence of pressure on time during pulsing generation ............... 103

Figure 4.2.1.2 – Pressure behavior at the inlet of the sandpack during PPT CO2 Injection

......................................................................................................................................... 106

Figure 4.2.1.3 — Recovery factor behavior during conventional CO2 injection with

following PPT CO2 injection (T=120 sec) ..................................................................... 107


following PPT CO2 injection (T=180 sec) ..................................................................... 110


following PPT CO2 injection (T=60 sec) ....................................................................... 114


following PPT CO2 injection (T=60 sec) at ultra high flow rate ................................... 117

Figure 4.2.2.2 — Oil cut behavior during conventional CO2 injection with following PPT

CO2 injection (T=60 sec) at ultra high flow rate ............................................................ 119


following PPT CO2 injection (T=180 sec) at ultra high flow rate ................................. 123

Figure 4.2.2.4 — Pressure behavior during conventional CO2 injection with following

PPT CO2 injection (T=180 sec) at ultra high flow rate .................................................. 124


following PPT CO2 injection (T=300 sec) at ultra high flow rate ................................. 127

Figure 4.3.1.1 — Recovery factor behavior during continuous CO2 WAG with PPT ... 133

Figure 4.3.1.2 — Recovery factor behavior during continuous CO2 WAG with PPT ... 138

Figure 4.3.2.1 – Recovery factor comparison: WAG vs Conventional waterflooding ... 142

Figure 4.3.2.2 — Recovery factor behavior during simple CO2 WAG with PPT .......... 145

xi

Figure 4.4.1 – Glass micro model pattern ....................................................................... 148

Figure 4.4.2- Schematic diagram of the experimental set-up with micro model ............ 150

Figure 4.4.3(1) - Results of PPT waterflooding with pulsing period 25 sec.a, b - micro

model at time 1 minute during conventional and PPT waterflooding respectively; c,d -

micro model at time 30 minutes during conventional and PPT waterflooding,

respectively. .................................................................................................................... 152

Figure 4.4.3(2) - Results of PPT waterflooding with pulsing period 25 sec. a, b - micro

model at time 60 minutes during conventional and PPT waterflooding respectively; c,d -

micro model at time 120 minutes during conventional and PPT waterflooding

respectively. .................................................................................................................... 154

Figure 4.4.4(1) – Results of PPT waterflooding with pulsing period 60 sec.; a, b - micro



respectively. .................................................................................................................... 156




respectively. .................................................................................................................... 157


model at 2 minutes during conventional and PPT waterflooding respectively; c,d - micro

model at 30 minutes during conventional and PPT waterflooding, respectively. .......... 159

xii



model at 120 minutes during conventional and PPT waterflooding, respectively. ........ 160

xiii

List of Abbreviations

µ - Dynamic viscosity

API – American Petroleum Institute

Bg - Volume factor

BS&W - Basic Sediment and Water

C - Conversion coefficient

CAPP – Canadian Association of Petroleum Producers

CO2 – Carbon Dioxide

cP – Centipoises (viscosity unit)

D – Darcy (permeability unit)

EOR – Enhanced Oil Recovery

HCPV – Hydrocarbon Pore Volume

Hz - Hertz (frequencies of pressure pulsing)

k – Permeability

MMP – Minimum Miscibility Pressure

n – Moles of gas occupy the volume Vgnc

NAPL - Nonaqueous phase liquid

NPV – Net Present Value

xiv

OOIP – Original Oil in Place

Pnc – Normal pressure 1 atm (101.325 kN/m2, 101.325 kPa, 14.7 psi)

PPT – Pressure Pulsing Technology

Prc – Reservoir pressure

PSI – Pounds per Square Inch

PV – Pore Volume

R – Gas constant

SAGD – Steam-Assisted Gravity Drainage

Si – Saturation by i

SOR – Secondary Oil Recovery

STB/D – Stock-Tank Barrel per Day

STO - Stock-Tank Oil

Tnc – Normal temperature 20oC (293.15 K, 68

oF)

Trc – Reservoir temperature

WAG – Water-Alternating-Gas

WF – Waterflooding

z – Gas compressibility factor

1

CHAPTER ONE: INTRODUCTION

One of the most important problems of the world is energy shortages which necessitates

technical progress. Oil composes a significant portion of the total world energy

resources. The diagram (Figure 1.1) shows the percentage of the five main energy

sources such as Hydroelectric, Nuclear Energy, Coal, Natural Gas and Oil.

As shown in this pie chart, Oil composes 36% of total energy resources. That’s why the

aim of this work is to increase oil recovery. Each type of oil requires other production

technologies.

From Figure 1.3, Canada is the most abundant owner of Heavy Crude Oil and Natural

Bitumen Deposits but it has few deposits of Conventional Crude Oil Reserves. Recovery

of heavy oil and heavy hydrocarbons is more complicated and expensive than recovery

of conventional light oil.

A heavy oil field has three development stages: Primary Recovery, Secondary Recovery

and Tertiary Recovery, also known as Enhanced Oil Recovery (EOR).

Primary Recovery – during this stage, oil is forced to the surface by energy which is

present in the deposit. In heavy oil deposits this stage is short or it can be absent.

Secondary Recovery — in this stage, the reservoir is subjected to water flooding or gas

injection (immiscible) to maintain a pressure that continues to push oil out.

2

Figure 1.1 – Oil part of total world energy resources (BP Statistical Review of World

Energy, 2007)

Hydro electric

6% Nuclear Energy

6%

Coal

28%

Oil

36%

Natural Gas

24%

3

Figure 1.2 - Worldwide distribution of heavy hydrocarbons (Elk Hills Petroleum 2010)

Middle East

Rest of the

World

Other western

Countries

USA

Canada

4

Tertiary Recovery — Tertiary Recovery, introduces fluids that reduce viscosity and

improve flow. The fluids could consist of gases that are miscible with oil (typically

carbon dioxide), steam, air or oxygen, polymer solutions, gels, surfactant-polymer

formulations, alkaline-surfactant-polymer formulations, or microorganism formulations.

Pressure Pulse Technology (PPT) was introduced in the Canadian oil industry in

September 1998 to improve the last two stages of oil field development (Dusseault and

Spanos 1999). Only after 2 years of laboratory experiments this technology was proposed

to the industry, as results showed that pulsation stimulation led to flow enhancement

(Wang and Dusseault 1998). Around 100 well stimulations were completed in Canada

without adding chemical into the flooding liquid, and successful results were achieved

(Dusseault and Cedric 2001)

Chemicals are used for flooding as they have a positive impact by stabilizing

displacement front, reducing oil viscosity, changing wetability and so on . Acid treatment

is traditionally used in limestone. Also acidizing in popular for sandstone reservoirs, as

it attenuate clay formations in the near-wellbore region that create an obstacles for fluid

flow or completely block it. If heavy oil is deposited in siliceous sandstones, engineers

are facing such challenges as changes of wetability, interfacial tension or asphaltene

precipitation. For this case, chemical treatment is efficient too.

Work Objectives

The main objective of this work was to investigate the implementation of PPT for

enhancement of traditional waterflooding, CO2 injection, WAG-CO2 process.

In details, the thesis objectives were:

5

- To compare oil displacement process during waterflooding with and without

implementing PPT. Find out optimal PPT parameters. To find dependence on oil

properties.

- To combine CO2 injection and Pressure Pulsing Technology. To estimate effect.

To optimize PPT parameters.

- To integrate Pressure Pulsing Technology into WAG-CO2 process. Investigate

simple WAG-CO2 with PPT as well as continues WAG-CO2.

- To create and manufacture micromodel. To get visual results of PPT during

waterflooding using the model.

Thesis organization

Chapter one: introduction – delivers information for general understanding of the world

potential and issues in petroleum industry and at the same time it gives overview of

advance technologies, including PPT, which could be used for solving the issues and

creating new opportunities in petroleum engineering.

Chapter two: literature review – includes description and results of a number of

laboratory experiments, field pilots and workovers that were done in the past and from

which main concepts of Pressure Pulsing Technology have been achieved.

Chapter three: experimental equipment and procedures – provides detail description of

experimental setup, preparation for the experiments and experiment run itself.

6

Chapter four: results and discussion – main part of the thesis, in which results of the

conducted experiments are presented, explained and discussed.

Chapter five: conclusion and recommendations – based on got results main conclusions

are given in the chapter. Also during experimental work a need in research of specific

regions was observed and recommendations for future work are listed.

7

CHAPTER TWO: LITERATURE REVIEW

2.1 Basic concepts

Pressure pulse technology (PPT) is a comparatively new technology which are used to

enhance the recovery rate of a nonaqueous phase liquid (NAPL) and to reduce solids

clogging in wells, permeable reactive barriers, and fractured media. The technology uses

steady, non-seismic pulse vibrations that generate a low velocity wave effect to

encourage flow of oils and small solid particles. It has been used for many years by the

Oil Industry to improve oil recovery from otherwise exhausted reserves.

Conduction of this technique (PPT) requires iterative applications of high pressure pulses

through sudden displacement of liquid in the wellbore. This is performed with a down-

hole desirable displacement process. The necessary equipment for PPT should be located

as close to the perforations as possible.

In this certain case no specific downhole tools were used, but the well casing replaced the

cylinder, and a piston was moved up and down by the service rig. As a result direct

mechanical impulse was created. Volume of the liquid in a wellbore increased rapidly,

creating a pulse. In case when blockages are created around perforations, generated

impulse of liquid destroys the blocking formations and opens the ports. The pulsations

will also impact near-wellbore region, removing re-compacted structures in it. This leads

to the free flow of hydrocarbons during well production. For an example, an 8 m stroke

is used in a 7” (178 mm) casing, pushing a liquid volume of 0.2 m3 (approximately1.25

BBL) per stroke. (Dusseault and Cedric 2001). As there is a range of the casing diameter,

8

and the stroke length could be different too, pulsation with different volume could be

generated. In order to create stronger pulse the maximum stroke is common in practice.

First, stroke is pushed down with high axeleration (in 2.5-5 s). Then it is kept at the

bottom (3-10 s) to let pulse energy spread from the well to the reservoir. The piston is

then pulled up slowly with a speed from 0.25 to 1 m/s, to the upper position. In general,

this return stroke takes 20-35 s and the total time for each pulse is around 30-60 s. PPT

workover stroking periods last for around 45-120 min, and are followed by 15 min

“station stop”. (Dusseault and Davidson 2001).

After each station stop, it is very important to measure the fluid level in the cylinder. It

could be done by acoustic methods. If measurements showed that liquid level has

decreased, additional liquid must be added into the well. In total, typical PPT workover

lasts from 5 to 24 hours (Dusseault and Cedric 2001) if the initial goal is to unblock the

well and re-establish sand flow. Stroking with different periods could be performed to

enhance the process and to reach the best results.

9

Figure 2.1.1 - Pressure pulsing workover stages (Dusseault and Cedric 2001)

10

Due to the rapid pulsing injection and high pressure amplitude near the wellbore, the

injection liquid enters all the possible pores even with a very low permeability. Pressure

pulse high permeability pores and fractures cannot transfer a huge volume of injection

liquid with high velocity. This liquid is made to seep into permeable parts of the matrix

and oil is pushed out even from low permeable parts of the reservoir.

During PPT, pore throat liquid movement is sudden and oscillating and a huge force is

created in any pore throat blocking materials. This force break the structure of blocking

materials and separate solid parts are transferred from a pore throat by the general flow,

reducing or eliminating blockages. (Figure 2.1.1) This unblocking effect has a long

distance impact on a reservoir.

The mechanism is described in the following way:

- During reservoir development, pore throats become blocked. PPT is applied

to remove the throats blockage.

- During PPT, the incompressible injection liquid volume changes quickly.

- This leads to rapid pressure jump at throats which partly remove blockages.

- Each pulse provides fewer blockages.

- Liquid flows faster and the displacement procedure takes less time in

comparison with the non-pulsing case.

11

-

Figure 2.1.1 - Pressure pulsing impact on pore throat blockages (Dusseault and Cedric

2001)

a

12

Another positive effect of PPT is overcoming capillary blockages. The mechanism of

overcoming of capillary pressure or interfacial tension is similar to breaking the structure

of blocking materials. Additional force has to be applied to overcome interfacial

(capillary) forces between oil and water.

PPT increases the injection rate which has a direct influence on the production rate. This

will result in an increase in oil recovery at some time in the future. The time required for

this increase in recovery influences the economics of the project. There is a direct

dependence - the sooner the increase in production, the better the economics.

After pressure pulse technology has been applied, a sharp growth in oil cut is achieved

and water cut decreases. Less injected water passes through high permeability pores and

fractures straight to the production well, but water enters low permeability regions and

pushes oil out. In other words, during flooding with PPT, there are far less water

fingering and pulsing generates better dispersion.

The injection rate significantly increases after PPT. This accelerates the reservoir

development without any negative effects and reduces economic costs. In some cases,

injection pressure decreases in some cases to 60% (Groenenboom and Wong 2003).

13

2.2 Laboratory research of pressure pulse technology

Experimental work is always important for development of a new technology and

application of it in a field. A lot of laboratory work has been performed since 1997, when

science became interested in PPT. Many experiments have been performed and all

showed different positive features of PPT. In this literature review several main

laboratory works to study PPT behavior will be examined with different parameters and

in different conditions. This will provide an idea of what to expect from PPT in the field.

High-amplitude cyclic pressure pulsation rapidly raises the injection volume of the

specific liquid (water, chemicals..) in the flow direction. Due to a bid number of

experiments - this is applicable for single phase liquid and two-phase liquid flow under

different conditions and system characteristics. In case if significant amount of free gas

in the system, PPT is less ineffective due to energy lost for compressing the gas.

Different scientists conducted their experiments with different parameters, boundaries

and conditions (design of a model, packing material size, oil viscosities, and flow

varieties (production with or without sand).With respect to oil viscosities injection rate

was also changed in wide range. The positive flow rate effects was observed in

sandpacks when saturation or fabric are constant, and under conditions of fixed external

pressure.

Several of the most valuable experiments gave not only quantitative but also visual

results of PPT impact on displacement process. From results got using glass model, we

can claim that PPT stabilizes displacement front and decrease viscous fingering. Even

14

old static water flooding, which have not been lucrative and have been shut down, can

become economically profitable.

Two main flooding models were used in laboratory investigations: cylindrical sandpack

with pressure transducers ports and rectangular glass model. In one series of laboratory

experiments, which were presented and published in the CIM Regina Technical Meeting,

Oct 1999. Mentioned above, cylindrical cell model is presented in Figure 2.2.1. The cell

is packed with sand, densified using vibrodensification, and sealed. To increase the

density of sand, it is packed bu application of 1 MPa axial stress. Along the cell

connections are fused in for connection of pressure recording equipment or other data

reading and recording devices. (Davidson and Spanos 1999).

Another type of flow cell that were also used for pressure pulse experiments are

rectangular flow cells (Figure 2.2.2). They are built with parallel transparent plates (0.15

and 0.75 m2), which are made of clear glass 20-30 mm thick, put vertically and packed

with sand. When the cells are full of sand, the inlet and outlet platens are installed. As the

result, the sandpack is tightly seating in place. Due to the aim of research, the glass

model may be placed in different positions, as a result the flow inside the model can be

“uphill” or “downhill”.

15

Figure 2.2.1 - Laboratory setup for investigation PPT (Davidson and Spanos 1999)

16

Figure 2.2.2 - Setup with glass flow model for conducting PPT experiments (Davidson

and Spanos 1999)

17

For convenience, all the experiments are labeled with numbers (e.g. LE 1 - Lab

Experiment 1). Consider LE 1. The system had the following parameters: A coarse-

grained sand pack with porosity 35% and permeability 5-8 Darcy. Used sand was oil wet

(35 cP oil) with a residual oil saturation. Then the model was saturated with mobile agent

- glycerin with viscosity of around 50 cP. The typical test procedure is presented below

(Davidson and Spanos 1999):

1. A constant head (∆p) is established along the model;

2. Steady-state flow rate is achieved;

3. Then the head value is changed, to confirm that the flow in a sand pack can be

described by Darcy’s law;

4. Afterwards the model is stimulated by pulsations at the its inlet;

5. Pressure pulsation is stopped for a similar interval of time, and then repeated. Due

to the project, different quantity of PPT cycles could be performed. Last stage is

quiet period without stimulation;

6. When experiment is completed, period of pulsation, the pressure gradient (∆p),

the pulsing amplitude, frequency of pressure pulsation was changed. Also

different types of fluid are used to conduct displacement process.

The experiment resulted in flow rate increase for around 50%. Major part of experiments

showed that saturation of the sandpack was not changed during experiment. The injection

pressure (∆p) had at the same value, and the fluids remained constant. Changes in

hydraulic conductivity, phase permeability, or other factors had no impact on the flow

improvement.

18

LE 2 was similar to LE1 except for one condition - sand was produced together with the

glycerin. In this case, enhancements of flow rate were coming up to 100%. As sand was

moving out of the model, the geometry of the model and boundary conditions were

changing too. The flow completely returned to the initial flow rate when pulsing was

terminated.

Another experiment, LE 3, was conducted in a model packed with quartz sand with

porosity around 35%, connate water saturation Sw close to 10 %, saturated heavy oil

(approximately 90%). Brooks dead crude oil with viscosity1600 cP), injection pressure

was equal 1 m head, and vertical flat plate simulator. In the dynamic case, pressure

pulsing stimulation was performed for around 38 min.

During the experiment, oil flow increased and remained stable, and then contained

substantially maximum oil cut for entire 38 min. Also flow rate was significantly higher

than for the conventional flooding test. General oil and water cut of the produced fluid

was calculated after the experiment was terminated. In case of conventional

waterflooding, water content was 65% and in the pulsing case- water cut decreased to

only 10% of the fluid. As a result recovery factor was over 25%. In general PPT

increased fluid flow but the oil cut did not decline, the sweep efficiency was high for a

significant period of time, and total recovery factor was desirable too.

LE 4 was conducted in a model with porosity of approximately 35% quartz sand, without

connate water saturation, saturated (100%) with paraffin oil. Oil viscosity 35 cP and

injection pressure was equal to 0.5 m head.

19

35 cP paraffin oil was used and the entire experiment was conducted for less than 6 min.

In case of oil with higher viscosity it took around 40-200 min. Figure 2.2.3 (a, b, c, d)

presents 4 photos of the glass cell at the comparable time in order to analyze injection

with and without pulsations. During PPT injection, the water is dispersed equally through

the model and, it led to low level of viscous fingering and high sweep efficiency. Also

the displacement process took much less time: At last pictures of both models, the

flooding with PPT was substantially complete and significant oil cut remained during the

pulsing injection (Dusseault and Davidson 2000).

Obvious, Pressure Pulsing Technology with certain parameters reduces fingering and

provides more stable and uniform displacement front. The pictures were taken at the

same time, and we can see that during pulsation injected fluid is moving much quicker.

20

Figure 2.2.3 - Comparison results of non-pulsing and pulsing waterfloodings in glass mo

dels (Dusseault and Davidson 2000)

21

Another series of laboratory investigations include over 60 tests. They were conducted

with a wide range of variables including (Cable and Dorey 2001):

- Pulsing and traditional floodings with several different constant head.

- Different fluids with viscosities of 25.5 cP and 2.5 cP for light paraffin oil and

dekalin respectively.

- Alternating frequencies of pressure pulsing.

- Different approach for pulsing generation.

- Variable packing material and procedure.

Several main results of the tests are shown, to show the influence of PPT under varying

system parameters. Firstly, the phase flow measurements are presented (Cable and Dorey

2001):

1. Unconsolidated sand with 2.5 cP oil

In the pulsed measurements, slightly reduced flowrates are noticeable compared with

unpulsed measurements. The tests with and without PPT showed similar value of

permeability. By the permeability real averaged pressure gradient was advised, instead of

nominal head, outlined by the constant pressure design.

2. Unconsolidated sand with 25 cP oil

The test resulted in increased flow under pulsed conditions but that could occur due to

increased pressure differentials. During traditional injection and injection with PPT the

sandpack behaved analogically to previous experiment with with 2.5 cP oil.

22

In the article, “Fluid Enhancement Under Liquid Pressure Pulsing at Low Frequency”,

Wang and Dusseault propose that new pulse should occur before the previous one lose its

energy. This type of pulsation was called “synergetic pressure build up”. Manual pulse

allowed to push average volume of 0.91 ml at a time. Those pulsations led to better

results than in case of by the mechanical pulsations. During 15 minutes around 270

pulses were generated. A considerable production enhancement was achieved. The flow

rate increased from 3.96 mL/h to 81.4 mL/h, while performing conventional and pulsing

flooding respectively.

Also manual pulses led to increase of inlet pressure to around 11 psi, and mean pressure

gradient was around 10.4 psi.

3. Consolidated sand saturated with 25 cP viscosity oil

The experiment was conducted in a sandpack filled with consolidated sand with

approximate permeability 100 md, and saturated with 25cP oil. The flow circuit was used

where the pulsation pump introduced the pulsations to the core. The experiment resulted

in considerable flow improvement. Also, flow enhancement was always followed by

pressure gradient increase. Using regression analysis, it was noticed that effective

permeability remained the same during traditional waterflooding, pulsing injection and

manual pulsations. The consolidated core attenuated more than the sandpack.

The series of laboratory investigations included tests conducted with two phase flow. As

in previous experiment, the same sandpack with consolidated sand was used. Before the

first pulse injection study, the sandpack was aged for some time in stock tank oil (STO).

This sandpack had an intermediate/mixed wetting characteristic. Waterflooding was

23

driven through the sandpack which was initially saturated with light paraffin oil to match

the study conducted by Davidson (Davidson and Spanos 1999). The waterflooding

procedure was the same for each test. Traditional waterflooding with flow rate of 4 mL/h

was continued by pulsations with flow rate of 400 mL/h.

The first two waterfloods (WF1 and WF2) were performed without pressure pulsing. An

instantaneous pressure transient (+0.3 psi) was measured when the breakthrough occure

for both waterfloods. There was water-wet behavior at the saturations. That’s why

breakthrough was belayed as the water pressure had to increase in order to cope the

capillary pressure. This pressure change did not occur during the PPT injection (WF3).

The absence of pressure transients is indicative of an oil-wetting character system and the

breakthrough occurred earlier in the case of pulsed waterflooding.

The saturation profile pre-breakthrough was heterogeneous (Cable and Dorey 2001).

Specific regions that had more oil wetability than other regions of the sandpack were

observed. The injected brine was unable to irrigate the areas from the very beginning,

until the inlet pressure of continuous water phase overcomes capillary pressure.

Nevertheless, at later period of flooding, after breakthrough was recorded, the injected

fluid was distributed through the porous media more homogeneous. The results of the

tests also showed that the highest residual oil saturation was presented at last 100-150

mm of the core length. However, the local “inlet effect” is much more dramatic. This oil

retention will decrease the measured core averaged brine permeability in comparison to

the true reservoir permeability.

24

Differential pressure drop for the PPT injection (WF3) was considerable. Also during

injection with pulsations the oil was produced slower: 0.65 PV was extracted after a

brine got to the outlet of 2.25 PV, in comparison with 0.78 PV and 0.74 PV for the

conventional waterfloodings one and two, respectively. Pressure decline and oil flow rate

data showed a long post breakthrough recovery of oil.

25

2.3 Field experiments of pressure pulse technology

A great variety of laboratory tests have been performed since January, 1997. In many

cases, high amplitude cyclic pulsing stimulation of porous media resulted in positive

changes of production. In general flow enhancement could be as large as a factor of 2 - 4

(Spanos and Davidson 1999). Based on the results, pressure PPT as a new EOR approach

was introduced to the industry and a field pilot was conducted in Alberta, 1998.

Field trials resulted in positive changes in production. Production rate was increased,

water cut was declined and oil content raised up. Main field scale experiments are

presented in Table 2.3.1. PPT is useful for pulsing stimulation of conventional and heavy

oil reservoirs during primary, secondary and enhanced oil recovery. This PPT technology

stabilizes viscose fingering in a system with different viscosity fluids and significantly

delays termination of heavy oil production.

As pressure pulsing has been successful at the laboratory, the next logical step is its

implementation in a field. The main goal is to identify the influence of pulsing spreading

in multiple directions, heterogeneities and extinction on porosity spreading on PPT

results in heavy oil deposits. Positive laboratory results, much promising theory and need

in nnew EOR technologies motivated a field pilot project. The first who decided to

participate in this project was the technology group at Wascana Energy Inc. (Spanos and

Davidson 1999). It was decided to perform continues pulsations in the central well in a

projected five-spot flooding and monitor production data in four other producers.

26

Table 2.3.1 – Main field scale experiments and their results

# Date Location Pre-PPT Recovery method

Type of PPT

Special features Results Source

1 January

2004

Queens, New

York

Static

Water

flooding

PPT

Water

flooding

In order to ensure that

injection proceeded at,

or close the water

table, the injection

well was monitored at

18 feet, one foot under

the water table.

Positive impact of PPT on the

displacement of the NAPL could be

explained by next facts: water level

changes, changes in product

thickness and measurability and

product repetition following

pumping.

TJT (Tim) Spanos and

Brett

Davidson.Pressure

Pulse Technology

(PPT): An Innovative

Fluid Flow Technique

and Remedial Tool

2 Not given Tonawanda,

New York

Static

Water

flooding

PPT

Water

flooding

The impacted part of

the reservoir was

located 20 feet below

grade and was created

by two geologic

zones: alluvial zone

with low permeability

underlying a grave

zone with higher

permeability.

PPT led to more intensive flow of

water through the zone with low

permeability, confirming the ability

of PPT to decrease the difference of

flow through regions with

heterogeneous permeability.


Brett

Davidson.Pressure

Pulse Technology

(PPT): An Innovative

Fluid Flow Technique

and Remedial Tool

Part 1/6 ( Please, see next page)

27



Type of PPT


3 Not given Austin, Texas

Static

Water

flooding

a) PPT

water

flooding

b) PPT

surfactant

flooding

The goal of the study

was to estimate the

ability of pulsation to

improve surface

dispersion and

increase creosote

recovery (less than

50% of the creosote

was recovered)

a) Pressure pulsing waterflooding

led to enhancement of creosote

recovery of 10- 15% over traditional

flooding

b) Combination of surfactant with

PPT waterflooding resulted in

99.8% of the creosote with a starting

saturation of 10.5% after injection of

3.3 PV of surfactant.


Brett Davidson.

Pressure Pulse

Technology (PPT): An

Innovative Fluid Flow

Technique and

Remedial Tool

4 Not given Broomfield,

Colorado

Static

bromide

flooding

PPT

bromide

flooding

During injection of a

bromide, very low

permeability of silty

clay was observed.

PPT injection resulted in increase of

flow intensity; it took twice less

time for the bromide tracer to get to

the observation wells in comparison

with traditional waterflooding.

TJT T. Spanos and

Brett Davidson.

Pressure Pulse

Technology: An

Innovative Fluid Flow

Technique and

Remedial Tool


28



Type of PPT


5 November

1998

Lloydminster

zones of the

Upper

Mannville

Group, Alberta

Static

Water

flooding

PPT water

flooding

4 wells were observed.

In 3 wells decreasing production

rate was change to increasing the 1st

well -0.41 to +0.41 m3/day, 2

nd -0.01

to+ 0.01 m3/day, 4

th -0.033 to +0.03

m3/day. Only in well #3 the

decreasing was reduced -0.074 to -

0.005 m3/day.

T. Spanos, B.

Davidson, M.B.

Dusseault, M.

Samaroo. Pressure

Pulsing at the Reservoir

Scale: A New IOR

Approach. 1999

6 March

2001

Lone Rock,

Saskatchewan

field

Static

Water

flooding

PPT water

flooding

Approximately 10,000

cP heavy oil reservoir

in the Sparky sand

with porosity of

around 30%, that was

shut-in since 1970.

Waterflooding with pulsations

enhanced the injectivity of this well

in twice, proving that PPT could be

used for increasing the injection rate

of wells.

T. Spanos, B.

Davidson, M.B.

Dusseault, M.

Samaroo. Pressure

Pulsing at the Reservoir

Scale: A New IOR

Approach. 1999


29



Type of PPT


7 1999 Alberta,

Canada

Static

Water

flooding

PPT water

workover

Heavy oil field

with10,800 cP viscose

oil. Improvements of

oil flow had been seen

at wells 300m away

from the stimulated

well.

1.The perforations blockages

became removed. 2. Mechanical

skin in the near-wellbore region was

perturbed and easier to remove. 3.

PPT helped to drive out fines and

asphaltenes. 4. Oil trapped zones

were reconnected with general flow,

sweep efficiency was increased.

Maurice B. Dusseault,

Brett C. Davidson, Tim

J.T. Spanos. Pressure

Pulsing for Flow

Enhancement and Well

Workovers. 1999

8

December

1998 to

February

1999

Alberta,

Canada

Static

Water

flooding

PPT water

flooding

10,800 cP heavy oil

reservoir.

1. PPT was not successful in

significantly depleted reservoirs

with a lot of free gas.

2. The pulsing amplitude of was

important; Big impulses led to better

result than small ones.

3. The production was increasing

slightly.

Maurice Dusseault,

Brett Davidson, Tim

Spanos. Pressure

Pulsing: The Ups and

Downs of Starting a

New Technology. 2000


30



Type of PPT


9 2001 Lloydminster

region, Canada

CHOPS

(primary

recovery

factor 5-

9%)

Chemical

flooding

(Surface-

active

chemicals)

Reservoir saturated

with ≈12,000 cP heavy

oil. Asphaltene content

was approximately

5-6% . Porosity of

unconsolidated sands

was 30-32%. One well

production was 100%

water, that’s why it

was stopped for

several months before

stimulation

7wells showed sharp enhancement

in total production:1. In general, a

factor of 2.3 enhancement was

recorded. 2. The oil production rate

was increased by a factor of 5. 3.

The oil/water ratio increased after

the stimulation from a total value of

0.16 to 0.43. 4. After stimulation,

production was on average 160 m3

/month of oil and 55 m3/month of

water, raising oil/water ratio to the

valu of about 3.

Maurice Dusseault,

Cedric Gall, Darrell

Shand and Brett

Davidson, Kirby

Hayes. Rehabilitating

Heavy Oil Wells Using

Pulsing Workovers to

Place Treatment

Chemicals. 2001


31



Type of PPT


10 1999 Lindbergh

Field

CHOP

PPT water

flooding

Was shut in for 15

months after a sharp

decrease in

production.

The well production increased to

over 8 m3/day several months after

the PPT workover.

Maurice B. Dusseault,

JTJ (Tim) Spanos,

Brett C. Davidson. A

New Workover

Approach for Oil Wells

Based on High

mplitude Pressure

Pulsing. 1999

11 1999 Morgan Field CHOP PPT water

flooding

Was developing by

CHOP flow but

production was never

higher than 1 m3/d.

The well increased its production up

to 5.5-6 m3/day, and had continued

to produce beyond the common

production trend for that well.

12 1999 Luseland Field CHOP PPT water

flooding

Had produced 60,000

m3 of heavy oil and

over 1000 m3 of sand).

Did not show an enhancement in oil

rate, compared to pre-PPT

waterflooding, what can be

explained by massive depletion.

Part 6/6 ( The end of the Table)

32

One of the main requisition for the field trial location was a reasonably intact reservoir.

Also, it must not have been subjected to EOR methods: Thermal, chemical or any other

that can alter its properties, as it could bring many uncertainties to the pilot. Indeed, a

candidate reservoir must meet certain criteria. It must have low free gas content, must not

be massively depleted and its permeability must be high. Injector and producers had to be

perforated within one geologic formation. Indeed, the geologic horizon in which the wells

were perforated should not have anomalous zones with any significant permeability

heterogeneity, fractures, faults and so on.

All the assumptions are supported by the data. Considerable enhancement in collective

oil production and oil cut were noticed during the field trial. In general, oil production

rose for over 37%, and oil cuts were significantly increased in sometimes up to over 20%.

The negative result of the PPT is that sand content increased from 0.5-1% to

approximately 4-10%. That is why potential sand movement in the porous media can be

responsible for production rate increase. The results of the field scale tests appeared to be

positive. Characteristics of 4 selected observation wells are described below for period

before and after implementation of PPT .

Well #1

This well exhibits highly variable and cyclical oil rates and oil cuts, and from time to

time this well did not show any production. Oil production rate for November, 1998

(static waterflooding) decreased. However, post-pulsing oil rate increased. Oil production

rate for February, 1999 was the highest production the well had ever reached during eight

years time period of its production history. Total during conventional waterflooding fluid

33

production rate for this well was constantly declining at a rate of approximately 0.041

m3/day. Moreover, water cut increased at a rate of approximately 0.031%/day, which

means that oil cut was decreasing. After PPT stimulation production rate was changed to

increasing trend of approximately 0.041 m3/day. The post-pulsing basic sediment and

water cut show a decline of around 0.125% /day.

Well #2

Total production history for this well during the time period before and after PPT

stimulation is similar to the production history of well #1. Before pulsations, fluid

production decreased at approximate rate of 0.01 m3/day. Conversely, after PPT fluid

production rate also increased at approximately 0.01 m3/day. The same value as the pre-

pulsing trend but at an increasing rate. These results show a 100% reversal from the

flooding before pulsations. The highest oil cuts and oil production rates were recorded

during December, 1998 and January, 1999. The production rates were increased up to 6%

in comparison with the highest oil rate ever given by the well since re-perforation was

done. The increased production was also the most significant enhancement noticed since

re-completion of the well.. In general, Well #2 showed similar trends to Well #1, as the

decreased oil rate changed to an increased rate and basic sediment and water cut were

reduced.

Well #3

Pre-PPT total fluid production tendency for well #3 decreased at approximate rate of

0.074 m3/day. In spite of the similar production trend of well #3 to two previous wells,

34

post-pulsing total fluid production did not increase production rates. Moreover, it showed

a negligible decrease of around 0.005 m3/day. Another negative aspect was that pre-

pulsing BS&W cuts were 19% while after PPT its rate rose up to about 41.5%.

Well #4

Initial production history of well #4 indicated 0.033 m3/day decline in total production.

After pressure pulsing stimulation total production of well #4 shows positive changes in

production rate, as it started increasing with the value of 0.003 m3/day. The pre-PPT

BS&W content was aaround 26%. The post-PPT BS&W cut for December, 1998 was

close to 26.9%. The measured post-pulsing basic sediment and water cut for February,

1999 was around 14%. This well shut in for four days in January, as it was sanded in,

that’s why four days of production were lost. Both oil cuts and production rates for this

well express a straight-line decline trend during pre-PPT period. Post-stimulation well

production rates were described by stabilization of oil and water cuts, while there was an

increase of oil content of around 16%.

Another series of the first field-wide pulsing project were performed and positive results

were achieved. The first field test began in December, 1998 and lasted until February,

1999 (Spanos and Davidson 1999). The project was conducted on a field that did not

have optimal characteristics due to high extraction ratios and free gas. Nevertheless, even

being a poor candidate for PPT, after 10.5 weeks, the decline production trend stopped

and the production rate was even gently climbing. Unfortunately, due to problems in the

company and the argument that the price of heavy oil was too low, it was not justifiable

to pursue commercial experimentation.

35

Two other pilots were conducted, one after the other. A second field-scale project was

performed in the summer of, 1999, and the third started in September of the same year.

The third project was a waterflood in a 10,800 cP heavy oil reservoir. The production

trend showed a sharp fall in production. During the three pilots, the performance

parameters of the PPT had a significant influence on the types of flooding. Changing the

rate, volume, frequency of pulses improved results in specific cases.

After a series of successful laboratory experiments, it was decided to apply PPT as a

workover method and as a field-wide stimulation method in Canada. More than 50

workovers were performed, and full field stimulations were completed on three fields

until 1999 (Dusseault and Davidson 1999). The special feature of all the developments

was that they were conducted in a heavy oil (10,800 cP) reservoir.

The workovers were performed under aggressive pressure pulsing in an oil well, without

injection of additional liquid. Overall, when the work was performed, several desirable

effects were achieved:

1. Strong porosity dilation waves helped displace structures of blocking

materials and asphaltenes.

2. The perforations became unblocked.

3. The porescale inertial effects helped to connect inactive blocked regions of oil,

adding them to general displacement flow.

4. Mechanical skin in the near-wellbore region was partially attenuated and

easier to remove.

36

As common workovers, a PPT workover is conducted with the synchronous injection of

different liquids, such as reservoir compatible oil, a workover liquid for reducing surface

tension and capillary blockage, or acid. During each pressure pulse, up to 5 per minute

for workovers (Dusseault and Davidson 1999), a limited amount of the work liquid is

injected into the reservoir during the pulse rise time. Pulsing reduced viscous fingering

and permeability channeling. Other positive features of PPT were that it improved the

dispersion around the workover well, greatly increasing the contact volume and the

overall efficiency of the liquid displacement method. PPT workovers are very effective in

establishing or re-establishing sand inflow. A positive impact on oil flow had been

noticed at wells 300 m away from the workover well (Dusseault and Davidson 1999).

To conduct a full-scale field stimulation one well was continuously pulsed for months.

Nevertheless, the production rate of the off-set wells was significantly improved. From 5

to 20 pulses/minute were generated by a down-hole pulser that was actuated from the

surface. The pressure increase around the excitation well was reached without the

addition of liquid. PPT improved flow rates and considerably reduced pore throat

blockages.

It is well known that in heavy oil reservoir, at the pore scale in situ, the oil is a non-

Newtonian liquid. This is why a finite pressure gradient is required to move oil. A

porosity dilation wave, created with pressure pulse technology and its pore-scale inertial

effects can overcome this viscosity force. The heavy oil becomes mobilized and a

physical connection is maintained between the wells and the far-field pressure. According

to the results, PPT is used with great success during different types of waterfloods.

37

An example of a typical PPT in heavy oil reservoir is presented in a report by Dusseault

(Dusseault and Davidson 1999). The PPT waterflood started in 1999. Oil viscosity in the

reservoir was 10,800 cP. The well’s production history showed a rapid oil production

decline and significant increase in water influx. It was decided to convert a central well to

an injection PPT well. Another 10 offset wells were strictly monitored and compared to

their previous production. During 5.5 months, PPT reduced the decline in production rate

to raise field profitableness and continue field developing. Generally, income rose by

$50,000 per month, and PPT technology costs were valued under $25,000.

Due to the workover results, if the well has the desirable features, the economic successes

ratio is acceptable and production parameters are enhanced and constantly applied.

Despite a limited understanding of PPT, significant success was achieved in many

reservoir stimulations. Table 2.3.2 present wells location or reservoir basins where the

PPT workover had been performed until March 1, 1999 (Dusseault and Davidson 1999).

38

Table 2.3.2 – PPT workovers to march 02, 1999 (Dusseault and Davidson 1999) (part1/2)

Well Location Stimulation Date Comments

Hwy.17 Lloydminster, Sask. June 1, 1998 Four watered out wells. Some oil rate restored.

XXX 35-26W3 (Plover Lake) September 23, 1998 Production decline, water breakthrough.

XXX 36-25W3 (Luseland) October 5, 1998 60,000 m3 produced. Poor candidate. *(1)

XXX 55-5W4 (Lindbergh) October 5, 1998 Shut-in approximately 15 months. Low inflow.

XXX 45-27W3 (Marsden) October 8, 1998 Suspected permeability impairment.

XXX 35-26W3 (Plover Lake) October 14, 1998 Production decline. Below expected production.

XXX 52-4W3 (Morgan) October 20, 1998 Repeated cycles of production/shut-in. Poor producer.

XXX 35-26W3 (Plover Lake) October 21, 1998 Low inflow. Fracture pressure almost reached.

XXX 44-26W3 (Marsden) November 3, 1998 Gassy well with low inflow. Poor candidate. *(1)

XXX 35-26W3 (Plover Lake) November 9, 1998 Production decline. Below expected production.



XXX 36-25W3 (Luseland) November 24, 1998 40,000 m3 produced. Poor candidate. *(1)

XXX 44-26W3 (Marsden) December 3, 1998 Suspected permeability impairment.

39

Table 2.3.2 – PPT Workovers to March 02, 1999 (Dusseault and Davidson 1999) (part 2/2)

Well Location Stimulation Date Comments

XXX 60-4W4 (Bear Trap) February 2, 1999 On vacuum. No fluid in well. Below expected production.

XXX 60-3W4 (Bear Trap) February 5, 1999 Production decline. Below expected production.

XXX 53-2W4 (Marwayne) February 9, 1999 Production decline. Below expected production.

XXX 53-2W4 (Marwayne) February 11, 1999 No production. Major blockage suspected.

XXX 63-5W4 (Wolf Lake) February 18, 1999 Poor inflow. Below expected production.

XXX 63-8W4 (Wolf Lake) February 25, 1999 Production decline. Below expected production.

XXX 63-8W4 (Wolf Lake) February 27, 1999 Poor inflow. Below expected production.

XXX 63-8W4 (Wolf Lake) March 1, 1999 Poor inflow. Below expected production.

Notes:*(1) There was significant volume of gas phase behind the casing in two out of three wells (poor candidates) had. One of the

two observed wells turned to profitable side after the successful PPT stimulation. The third well had produced a lot of oil during long

time, and was significantly depleted in the CHOP-impacted area. Nevertheless, even if a well production oil rate was enhanced, it still

did not produce enough to cover costs of the stimulation in a projected period (approximately).

40

The PPT trial wells (fully confidential) were inactive CHOP wells that had started

unreasonable production of water/oil ratios. The pulsations in the wells were continued

for time intervals of 5-8 hours. Significant increase of fluid levels was recorded after the

stimulation. The pilot showed that in two cases, the wells gained acceptable oil

production.

One example is the Luseland Field of heavy oil. The cold heavy oil production well gave

cumulative production of 60,000 m3 of viscose oil and significant amounts of sand had

been produced. The well was stimulated during 10 hours with the PPT over its lifetime.

Unfortunately, there was no increase in oil rate, compared to pre-PPT production. The

results are explained by the fact that the well was a typical poor candidate due to the large

massive depletion.

Another well in the Lindbergh Field showed a rapid drop in production and was shut in

for 15 months. After the PPT treatment, it was started new production life as a profitable

CHOP producer. The production rate was over 8 m3/day several months later. The

production history of this well is presented in Figure 2.3.1.

41

Figure 2.3.1 - Well production history of Lindbergh oilfield (Dusseault and Davidson

1999)

42

Several approaches were made to setup CHOP flow using a well that started its

production in 1997 in the Morgan Field. But no success was achieved: the production rate

remained less than 1 m3/d. After six hours of PPT the well production rate increased up to

5.5-6 m3/day, and remained at high production rate.

Other example was different to all the previous ones, as it refers to poor candidate well

characteristics. One of the negative factors was that there was a significant amount of

natural gas behind the casing. As it was expected, PPT stimulation was not successful.

Similar behavior had other well, fluid was added to the annulus and mild, as a result,

short-term well production was achieved. That was an evidence that the Pressure Pulsing

Technology is not efficient in the wells where a lot free gas is present.

The PPT workover results on other wells had the same tendency. Several of them were

quite successful, especially cases where terminated wells were turned into lucrative

producers. Other wells were considered as successful due to an increase in production,

but that increase was not enough to cover the cost of PPT stimulation in short period of

time. Generally, the companies involved in conducting those workovers evaluated the

economic and the technical success ratio to be over 50%, and close to 90% respectively.

(Dusseault and Davidson 1999).

Chemicals were used as injection fluids to increase the efficiency of PPT. Several wells

that had been studied were about 600 m deep in one field with 16-17°API oil. The lowest

viscosity was around 1200 cP (Dusseault and Gall 2001), with some difference between

the wells. The asphaltene content was around 5-6%, and decreased under pressure

decline. In the lower thin region average initial oil saturation was 82%. In the top thicker

43

region the oil saturation was close to 85%. The wells were located in unconsolidated sand

formation with porosity of 30-32%. Send was produced with heavy oil (CHOP).

CHOP had been implemented on this reservoir with help of beam pumps for around 15-

20 years, after that it was terminated. The initial recovery factor in the upper region was

close to 9% and in the lower zone it was around 5%. Most of wells were not producing

until the PPT stimulation of the field was recently applied. Major number of wells was

perforated in both the lower region (2.5 m) and in the top terion (5 m).

Before PPT small amounts of sand were produced, but there was no significant sand

production at that time. The wells had no active water refilling, and no energy

compensation from any reservoir pressures.

Before pulsed chemical injection, six of the seven stimulated wells, had been producing

for several months. Because of very high water cut (almost 100% water) one well had

been terminated for many months.

The general results of the seven wells are presented in Figure 2.3.2. Three months of

conventional production for the six wells are shown in comparison with three months of

post PPT production for the seven wells. The pre-stimulation period of production

showed stable oil rates on a monthly average basis. A dramatic increase in liquid

production rates for all seven wells after PPT was recorded. In general, they were

enhanced by a factor of 2.3 (Figure 2.3.3).

44

Figure 2.3.2 – Pre- and Post-PPT Chemical treatment production behavior (Dusseault and

Gall 2001)

45

Figure 2.3.3 - Total monthly production behavior for three months before and after PPT

chemical stimulation (Dusseault and Gall 2001)

46

CHAPTER THREE: EXPERIMENTAL EQUIPMENT AND

PROCEDURES

The laboratory setup for conducting experiments with pressure pulsing technology

included: Sandpack model, back pressure regulator, pressure transducers, temperature

controller, transfer cylinder, syringe pump, CO2 and nitrogen cylinders and heating

device. The fluids were injected using a syringe pump and were produced through a back

pressure regulator set at 1,379 kPa (200 psi). The oil was injected not directly through the

pump but via a transfer cylinder. Gas injection was performed directly from a CO2

cylinder through a Bronkhorst® High-Tech Flow meter/controller, Model EL-Flow® F-

230M. Nitrogen and carbon dioxide cylinders manual regulators were installed on each:

ProStar Platinum® and Tescom Corporation, respectively. Regulator pressure gauges

WIKA® were installed: 0-4000 psi – Flow In and 0-1000 psi – Flow Out.

To keep back pressure constant and within an assigned range, a CoreLab® BPR Model

BPR-50-SS was installed and controlled with nitrogen pressure.

The pressure data was measured with Validyne® transducers, monitored and recorded

using Easy Sense® 2100 and MS® Excel software. Four different pressure range

transducers (1x5psi, 1x125psi, 2x200psi, 1x50psi, 1x20 psi) were used for the

measurements of pressure pulsing behavior within the system. Every transducer was

calibrated before each experiment. An AMETEK® portable pneumatic tester, Model

T730 was used for calibration. Also pressure gauges, 3D Instruments, LLC®, Model

DTG-6000 (5000 psi) and Accur Cal Plus (2000 psi), were used. The experiments were

47

carried out in an air bath at a constant temperature of 23°C. A Cole Parmer Digi-Sense®

Temperature Controller was used for this purpose.

Two types of automatic valves with timers were used. A single unit (valve + mechanical

timer) Canfield Connector®, Model ET-20-E was used. When the valve setting

parameters were optimal, a Hanbay® valve MDM-060DT-3-SS-41GXS2 with actuator

was installed and controlled with an Omega® PTC-15 - Programmable Digital Timer

with 5 Independent Relays. The experimental schematic is shown (Figure 3.1).

Oil viscosity was measured with a Brookfield® Programmable Viscometer, Model: DV-

II+.

48

Figure 3.1- Schematic diagram of the experimental set-up

LEGEND

- Three-way valve

- Two way valve

- Four way connection

- Three way connection

- Electronic pressure gauge

- 1/8 pressure line

- Data cable

- Boundaries of the air bath

1

4

5 6

7

8 9 12 13

14

3

10

73

11 15

16

3

1 – syringe pump

2 – CO2 cylinder

3 – check valve

4 – personal computer

5 – transfer cylinder

6 – pressure accumulator

7 – controlled solenoid

valve

8 – transducer #1

9 – transducer #2

10 – transducer 5 psi

11 – transducer #3

12 – manual pressure regulator

13 – N2 cylinder

14 – sandpack

15 – back pressure regulator

16 – test tube

17 – flow meter/controller

18 – temperature sensor

19 – heater element

20 – temperature controller

21 – power cord

12 2

17

18

19

20

21

49

Heavy oil and sandpacks were used in the experiments where oil was obtained from

CNRL heavy oil field located in Unity, Saskatchewan (Unity is located 200 km west-

northwest of Saskatoon, Saskatchewan, and 375 km southeast of Edmonton, Alberta).

The stock tank oil properties are given in Table 3.1. As the oil API gravity is higher than

10 and the viscosity of oil is higher than 10,000 cP, according to Ten – Ten Theory22

,

used oil must be categorized as heavy oil that requires unconventional recovery.

Brine solution was mixed using 1 wt% NaCl dissolved in deionized water. Sandpacks

were wet-packed using sand silica 530 and methanol. The model was filled with the

methanol, in the way that methanol was always was over the continuously pouring sand

by small portions into the model. During the entire packing procedure, the model was

impacted by vibrations. When the model was full with the sand –methanol mixture it was

left for 3 hours with connected to a vibrator. For 3 hours, the sand level was checked and

in the case of a low level, sand was added. After three hours, the methanol was drained.

The next step was drying the sand pack from methanol. An air compressor was connected

to the inlet of the sand pack and methanol was collected from the outlet. The drying

procedure lasted up to one hour. The packed sample measured 285 mm in length and 21

mm in diameter. Orifices for installation of pressure transducers were located 67.5 mm

from the inlet and outlet and 150 mm between each other (See Figure 3.3.)

To measure the pore volume, the imbibitions method was used. After a sand pack was

ready and completely dry, it was connected to a vacuum pump. A Fisher Scientific®

pump, Model: Maxima C Plus, was used for vacuuming the sand pack. The procedure

took up to 4 hours. When the vacuuming was complete, the inlet and outlet of the sand

were closed to maintain the vacuum. The inlet was connected to the plastic line and the

50

other end of the line was dipped into a vial with brine. When the inlet was opened, brine

filled the pore volume of the model. The difference in vial level reading before and after

water saturation shows the value of pore volume + dead volume (constant for certain

models).

For high accuracy weight measurements a Mettler Toledo® scale Model AG204 was

used.

For separating oil from water, a Fisher Scientific® CentrificTM

Centrifuge was used. In

general, separation was conducted at 7000 rpm for 25-30 minutes.

None of the experiments presented in the literature review cover research with oil as

heavy as the oil used in the experiments (13707 cP). In other words, the results of the

experiments provide a basic understanding of PPT impact on heavy oil displacement.

51

Table 3.1 – Stock-tank oil properties (Unity, Saskatchewan)

# Property Value

1 Temperature, °C 23

2 Density, kg/m3 960.3

3 API Gravity 15.9

4 Viscosity, mPa·s 13.707

52

Figure 3.2 – Ten – Ten Theory schematic interpretation (Tg. Rasidi Tg. Othman 2013,

SPE 165449)

53

Figure 3.3 – Schematic diagram of the sand pack used in the experiment

285mm

150mm 67.5mm 67.5mm

54

CHAPTER FOUR: RESULTS AND DISCUSSION

As the goal of this thesis is to determine the effect of PPT on immiscible displacement in

comparison with conventional water - or CO2 flooding, the first part of the laboratory

work was performed to set the base line. In other words, conventional water flooding was

conducted to determine the oil and water cut and pressure trends and recovery factor.

Due to the research purpose pulsation parameters (period and frequency) will be

expressed in terms of time (seconds), but for general purposes time value can be

converted to pore volume (PV) value by multiplying injection flow rate by time.

4.1 Investigation of Pressure Pulsing Technology impact on waterflooding. Influence

of oil viscosity and pulsing parameters on recovery.


saturated with 13707 cP heavy oil

The sand packs were prepared each time from the beginning of each experiment so the

properties of the sand packs fluctuated within a certain range. Model characteristics used

for conventional waterfloods are summarized in Table 4.1.1.1. Results of three traditional

waterfloods are presented in Figure 4.1.1.1. General pressure behavior is plotted versus

time in Figure 4.1.1.2.

In spite of the various properties for the sandpacks, the recovery factor RF changed

within a range of ± 2% with the values ranging from 27 to 29%.

55

Table 4.1.1.1 – Characteristics of the models used for conventional waterfloods

Sandpack

#

PV,

ml

Porosity,

%

Permeability,

D

Connate

water

saturation,

%

Initial Oil

saturation,

%

1 32.8 33 10.0 1.3 98.7

2 38.8 39 15.4 1.1 98.9

3 36.8 37 14.3 2.0 98.0

56

Figure 4.1.1.1.—RF vs PV injected during three conventional waterfloods

0

5

10

15

20

25

30

35

0 0.5 1 1.5 2 2.5 3

RF

(%

OO

IP)

PV Injected

Ex_3 Ex_2 Ex_1

57

Figure 4.1.1.2—Pressure vs Time during conventional waterflooding

0

10

20

30

40

50

60

70

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000

Pre

ssu

re,

psi

Time, sec

Ex_2 _conventional_waterflooding

58

Experiment 1.1 - Implementing Pressure Pulsing Technology at the late stage of

development

The goal of this experiment was to discover the effect of pressure pulsing technology at

the late stage of development. The results are quite important, as many oil fields are at the

late stage in development when waterflooding. A summary of experimental parameters

are collected in Table 4.1.1.2

After 2.5 PV was injected, the oil cut (Figure 4.1.1.3) and recovery factor (Figure 4.1.1.4)

remained constantly low. Pulsed waterflooding was applied when injection reached 4.5

PV. PPT injection lasted for another 1.5 PV of injection, but it did not lead to any

enhanced production.

Analyzing the results of the experiment, PPT did not have a significant impact on the

experiment. Neither a sharp oil cut nor an increase in recovery factor was noticed and the

trend stayed stable before and during the PPT. The results are shown in Figures 4.3 and

4.4.

The PPT, with the parameters used in Experiment #1.1, is not effective in the late stage of

development.

59

Table 4.1.1.2 – Summary of experiment #1.1

Ambient Temperature, °C 23

Pore Volume, cm3 32.8

Porosity, % 33

Permeability, Darcy 10.0

Initial Oil Saturation, % PV 98.7

Connate Water Saturation, % PV 1.3

OOIP, cm3 32.4

Injection Rate, cm3/min 0.1

Period of pulsing (T), sec 200

Time of one pulse (t), sec 3

Pressure jump coefficient 1.8÷2.1

60

Figure 4.1.1.3—RF vs PV injected during waterflooding with following PPT

0

5

10

15

20

25

30

35

0 1 2 3 4 5 6 7

RF

(%

OO

IP)

PV Injected

Waterflooding + PPT

Conventional waterflooding

61

Figure 4.1.1.4—Oil cut vs PV injected during waterflooding with following PPT

0

20

40

60

80

100

120

0 1 2 3 4 5 6 7

Oil

cu

t, %

PV Injected

Conventional waterflooding

Waterflooding with PPT

62

Experiment 4- Implementing high amplitude PPT, as an initial type of oil

displacement

Experiment #4 involved PPT from the beginning of the oil displacement procedure. On

one hand, the goal of the experiment was to discover if it was useful and resulted from

implementing PPT at the early stage of reservoir development. The results would show if

it were effective to replace conventional waterflooding with PPT waterflooding, as the

main type of secondary oil recovery. The optimal parameters leading to the highest

recovery factor were to be determined.

The experimental summary and parameters used in the experiment are presented in Table

4.1.1.3.

The purpose of this thesis is to compare PPT to conventional methods of oil displacement

and the results will be compared to results of the experiments with similar initial

conditions. As the Experiment #4 characteristics were quite similar to experiment #1, the

recovery factor and oil cut are compared in Figures 4.1.1.5 and 4.1.1.6, respectively.

63

Table 4.1.1.3 – Summary of experiment #4



Porosity, % 33




OOIP, cm3 32.3





64

Figure 4.1.1.5—Effect of PPT over traditional waterflooding, regarding RF

0

5

10

15

20

25

30

35

40

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5

RF

(%

OO

IP)

PV Injected

Ex_4 (Waterflooding +PPT)

Ex_1 (Conventional waterflooding)

65

Figure 4.1.1.6—Effect of PPT over traditional waterflooding, regarding oil cut

0

20

40

60

80

100

120

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5

Oil

cu

t, %

PV, Injected

Ex_12 (Waterflooding +PPT)

Ex_11 (Conventional waterflooding)

4

1

66

In spite of the fact that PPT was initiated from the very beginning, significant differences

in the results were only observed when 2.3 PV was injected. Before 2.3 PV was injected,

the results of conventional waterflooding and PPT flooding were almost identical.

Pressure profiles from this test were obtained from three transducers connected along the

sand pack, as is shown in the schematic diagram. The profiles show that each pulse was

recorded by all three transducers. The pressure trend from transducer #1 connected at the

inlet of the sandpack, in time intervals from 4400 – 5400 s is shown in Figure 4.1.1.7.

67

Figure 4.1.1.7—Pressure profile at the inlet of the sandpack during PPT

0

2

4

6

8

10

12

14

16

18

4300 4500 4700 4900 5100 5300 5500

Pre

ssu

re,

psi

Time, sec

68

Experiment 5- Implementing low amplitude PPT, as the initial type of oil

displacement

The goal of Experiment #5 was to investigate the impact of pressure pulsing amplitude on

the recovery factor. Similar to previous experiments, PPT was implemented from the

beginning of immiscible oil displacement. In comparison with Experiment #4, the

automatic valve was set to a shorter “close” period, the flow rate was left at the same rate

of 0.1 ml/min and the pressure jump amplitude was decreased. For the model of

experiment #5 the same oil and sandpacking and were used as in previous experiment.

The main experimental features and PPT parameters are summarized in a Table 4.1.1.4.

From this table, the system properties are similar to Experiment # 1 (conventional

waterflooding) and #4 (high amplitude PPT waterflooding) to allow comparison of the

three experiments. Two graphs with oil cuts - Figure 4.1.1.8 and recovery factors –

Figure 4.1.1.9 versus injected pore volume are presented.

From the graph displaying the recovery factor, the most successful type of displacement

was the Low Amplitude PPT. The recovery factor from conventional waterflooding in

Experiment #1 at 3 PV increased from 30% to almost 38%. By comparison to Low

Amplitude and High Amplitude PPT, the first one showed enhancements in production

after 0.8 PV was injected and at 3 PV the difference in RF was approximately 5 %.

In spite of low amplitude PPT, the pressure jump was recorded in all three transducers

along the sandpack. This means that the pressure jump impacts the entire sandpack: From

the model inlet to outlet.

General pressure behavior at the inlet of the sandpack is shown in Figure 4.1.1.9.

69




Porosity, % 32




OOIP, cm3 31.3





70

Figure 4.1.1.8—High and low amplitude PPT versus traditional waterflooding, regarding

oil cut

0

20

40

60

80

100

120

0 0.5 1 1.5 2 2.5 3 3.5 4

Oil

cu

t, %

PV, Injected

Ex_5 (low amplitude PPT)

Ex_1 (Conventional waterflood)

Ex_4 (High amplitude PPT)

71

Figure 4.1.1.9—Effect of low and high amplitude PPT over traditional waterflooding,

regarding RF

0

5

10

15

20

25

30

35

40

45

0 0.5 1 1.5 2 2.5 3 3.5 4

RF

(%

OO

IP)

PV Injected

Ex_5 (Low amplitude PPT)



72

Figure 4.1.1.10—Pressure profile at the inlet of the sandpack during PPT

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

16400 16500 16600 16700 16800 16900 17000 17100

Pre

ssu

re,

psi

Time, sec

73

Knowing the High Amplitude PPT provides worse results than Low Amplitude PPT

waterflooding, the rational decision is to decrease the pressure amplitude to a value

smaller than in Low Amplitude PPT. Hence, Ultra Low PPT waterflooding was

conducted in Experiment #6.

Pulsing characteristics for Experiment #6 and a short summary of properties for the

model used in the current experiment are listed in Table 4.1.1.4

Results for Ultra Low PPT waterflooding are compared with the results from

conventional, Low and High Amplitude PPT waterflooding in Figure 4.1.1.11.

From this graph the Ultra Low Amplitude PPT gave a negative effect in comparison with

Low Amplitude PPT. It did show an enhancement in comparison with conventional

waterflooding and High Amplitude PPT. The increase in recovery factor was around 5%

at the time when 3 PV was injected, in comparison to conventional waterflooding and

around 2 % over High Amplitude PPT displacement.

Analyzing this group of experiments, where heavy oil (13707 cP) was used:

- Pulsing parameters significantly impact results of the tests

- High pressure amplitude leads to lower oil recovery

- The best type of displacement for heavy oil with viscosity 13707 cP is Low

Amplitude PPT waterflooding (Pressure jump coefficient 1.2 ÷ 1.4)

74




Porosity, % 31




OOIP, cm3 30.1





75

Figure 4.1.1.11—Relation between RF and different range amplitude PPT and

conventional waterflooding

0

5

10

15

20

25

30

35

40

45

0 0.5 1 1.5 2 2.5 3 3.5 4

RF

(%

OO

IP)

PV Injected

Ex_5 (Low amplitude PPT)



Ex_6 (Ultra low Amplitude PPT)

76


saturated with 1020 cP heavy oil

The next set of experiments was performed to determine how oil viscosity impacted PPT

waterflooding results and how pulsing parameters changed with changing oil viscosity.

Conventional water flood was conducted from the beginning to establish a base line. In

this experiment different oils were used for oil saturation. Oil viscosity was 1020 cP at

23 C. All other system properties were the same as in previous experiments. General

properties of the used model are listed in Table 4.1.2.1.

To get better a understanding of oil viscosity influence on recovery factor, graphs

compared two conventional waterfloods with different types of oil. In Experiment #1

heavy oil with a viscosity of 13707 cP was used and in Experiment #7 less viscose oil

(1020 cP) was used.

Analyzing Figure 4.1.2.1, the oil cut was higher in the case of 1020 cP oil than in the case

of 13707 cP oil and kept this tendency until the end of the displacement. According to

Figure 4.1.2.2, oil viscosity decline lead to significant enhancements in production. For

example, at the point where 3 PV were injected, the recovery factor was around 30 and

43% in Experiments 1 and 7, respectively. The total RF difference was approximately

13%.

Sharp differences in recovery factor for different types of oils prove the theory that

Pressure Pulsing Technology may have other behaviors with different oil properties.

77




Porosity, % 33




OOIP, cm3 32.3


78

Figure 4.1.2.1 — Effect of oil viscosity on oil cut during traditional waterflooding

0

20

40

60

80

100

120

0 0.5 1 1.5 2 2.5 3 3.5

Oil

cu

t, %

PV, Injected

1020 cp oi (Ex_14)l

13707 cp oil (Ex_11)

7)

1

79

Figure 4.1.2.2— Effect of oil viscosity on recovery factor during traditional

waterflooding

0

5

10

15

20

25

30

35

40

45

0 0.5 1 1.5 2 2.5 3 3.5

RF

(%

OO

IP)

PV Injected

1020 cp oil ( Ex_14)

13707 cp oil ( Ex_11)

7

1

80

Experiment #8 - High Amplitude PPT

The next step in the laboratory research was to conduct High Amplitude PPT

waterflooding (Experiment #8). The goal of this experiment was to determine if Low

amplitude PPT had any impact on waterflooding. Also, it would a comparison of the

impact of PPT under different conditions, namely different oil viscosities.

Experiment #8 included High Amplitude PPT waterflooding. The experiment was similar

to Experiment #5, but oil used in the experiments was different: 13707 cP and 1020 cP in

Experiments #5 and #8, respectively. This part of the research toadied in determining not

only the impact of PPT on waterflooding, but also an estimate of how the results of PPT

depend on oil viscosity. Table 4.1.2.2 shows properties of the model.

For Experiment #8, the automatic valve was set for high amplitude, low frequency

pulsing and the same 0.1 ml/min flow rate used in the previous experiments was

assigned. The valve settings are shown in table 4.1.2.2.

Results of the High Amplitude PPT, for better understanding of the technological impact,

are presented with the results of conventional heavy oil displacement from Experiment

#7.

From Figure 4.1.2.3, the High Amplitude PPT induced an increase in oil cut at the

beginning and Figure 4.1.2.4 also shows a recovery factor enhancement at the early stage

of displacement. An increase of around 5% is noticed in RF from 0.5 to 1.0 injected PV.

After 1 PV the difference began to decrease and by 3 PV it came down to almost zero.

81

The oil cut behavior had a similar trend as shown in Figure 4.1.2.3. Significant increases

in oil cut were obtained at the beginning of the experiment. Oil cut was high only by 0.5

injected PV and after 0.5 PV the oil cut trend was almost identical to the conventional

flooding experiment.

High Amplitude PPT is not effective for current conditions and mainly for heavy oil with

viscosity of 1020 cP used in the experiment.

82




Porosity, % 34




OOIP, cm3 33.0





83

Figure 4.1.2.3— Effect of High Amplitude PPT on oil cut versus traditional

waterflooding

0

20

40

60

80

100

120

0 0.5 1 1.5 2 2.5 3 3.5

Oil

cu

t, %

PV, Injected

High amplitude PPT (Ex_15)

Conventional waterflooding (Ex_14) 7

8

84

Figure 4.1.2.4— Effect of High Amplitude PPT on RF versus traditional waterflooding

0

5

10

15

20

25

30

35

40

45

0 0.5 1 1.5 2 2.5 3 3.5

RF

(

% O

OIP

)

PV Injected


Conventional waterflooding (Ex_14)

8

7

85

Experiment #9 - Ultra High Amplitude PPT

The goal of Experiment #9 was to discover how pressure amplitude effects heavy oil

(1020 cP) displacement. From the previous experiment with High Amplitude PPT, there

was no sharp enhancement in production. The pulse period and pressure amplitude was

increased.

For Experiment # 9 all the same materials were used as in Experiments #8 and # 7. The

characteristics of the model and pulsing parameters are presented in Table 4.1.2.3.

To compare High Amplitude and Ultra High Amplitude PPT flooding against

conventional waterflooding, the results of experiments #7, #8 and #9 are shown in Figure

4.1.2.5 (oil cut trend) and Figure 4.1.2.6 ( recovery factor behavior).

From the recovery factor graph, the Ultra High Amplitude PPT lead to a significant

increase in recovery factor, in comparison with traditional oil displacement by water, at

an early period of displacement (by 0.7 PV injected), but later, a negative effect is seen.

Indeed, after 2 PV of injection, the recovery factor decreases to the point where its value

is even lower than in case of conventional waterflooding. Comparing High Amplitude

PPT and Ultra High Amplitude PPT, the second technology slightly overcomes the first

at the beginning but constantly shows worsening results starting from the point where 0.8

PV was injected.

A similar trend describes oil cut behavior. From Figure 4.4.2.5, starting from 0.4 PV, the

oil cut during Ultra High Amplitude PPT was lower than in two other cases.

86




Porosity, % 33




OOIP, cm3 33.0




Pressure jump coefficient 4÷7

87

Figure 4.1.2.5— Comparison of Effect of High and Ultra High Amplitude PPT on oil cut

versus traditional waterflooding

0

20

40

60

80

100

120

0 0.5 1 1.5 2 2.5 3 3.5

Oil

cu

t, %

PV, Injected



Ultra High amplitude PPT(Ex_16)

8

7

9

88

Figure 4.1.2.6— Comparison of Effect of High and Ultra High Amplitude PPT on RF

versus traditional waterflooding

0

5

10

15

20

25

30

35

40

45

0 0.5 1 1.5 2 2.5 3 3.5

RF

(%

OO

IP)

PV Injected



Ultra High amplitude PPT (Ex_16) 9

7

8

89

Experiment 10 - Low Amplitude Pressure Pulsing

Increasing the pulsing amplitude leads to decreased oil cut and recovery factor. This is

why Low Amplitude Pressure Pulsing was conducted in Experiment 10. To establish this

type of pulsing, the controlled automatic valve was set to period of pulsing – 25 sec.

The experimental model and external condition of run #10 were the same as in

Experiments #7, #8 and #9. The general properties of the model and main pulsing

features used in Experiment #10 are summarized in Table 4.1.2.4

The results of the experiment conducted under Low Amplitude PPT are in the same graph

as three previous experiments: #7 – Conventional waterflooding, #8 and #9 High and

Ultra High Amplitude PPT, respectively.

From Figure 4.1.2.7, there is a significant enhancement in immiscible oil displacement

during Experiment 10, where the Low Amplitude PPT was performed. The RF was

established dramatically higher than it was in case of conventional waterflooding and was

high by the end of displacement. An absolute increase at the point where 3 PV was

injected was approximately 9%. Even in comparison with High and Ultra High PPT

waterflooding, Low Amplitude PPT waterflooding showed better results from the

beginning, where RF was close to the High and Ultra High PPT, until the end of

displacement, where improvement became significant.

In spite of the Low PPT setting, from pressure transducers data (see Figure 4.1.2.8) the

pressure jump was recorded even by a third transducer, which was located at the far end

of the sandpack. The power of the pressure jumps decreases with an increase in distance

between the pulsing source and transducer location.

90




Porosity, % 32




OOIP, cm3 31.2





91

Figure 4.1.2.7— Comparison of Effect of Low Amplitude PPT over High, Ultra High

Amplitude PPT and traditional waterflooding on RF increase

0

10

20

30

40

50

60

0 0.5 1 1.5 2 2.5 3 3.5

RF

(%

OO

IP)

PV Injected



Ultra High amplitude PPT (Ex_9)

Low amplitude PPT (Ex_10)

92

Figure 4.1.2.8— Pressure behavior in the sandpack during Low Amplitude PPT

waterflooding.

0

0.5

1

1.5

2

2.5

3

5690 5700 5710 5720 5730 5740 5750

Pre

ssu

re,

psi

Time, sec

Trancduser #1 (125psi) Trancduser #2 (50 psi) Transducer #3 (20psi)

93

Analyzing the results, the lower amplitude of PPT waterflooding gives better results. Due

to this tendency, the decision to conduct Ultra Low PPT was made. As the current

automatic valve with a mechanical timer could not be set to a period less than 25 seconds,

it was replaced by a new valve with an actuator (Hanbay®) and electronic timer

(Omega®). This equipment can set the pulsing period down to 15 seconds. The main

parameters of the Ultra Low pressure pulsing are given in Table 4.1.2.5.

The same preparation procedure was used to keep the system properties close to

Experiments 7-10. The system properties showed slight differences in porosity and

permeability. A short summary of the current experimental properties are shown in Table

4.1.2.5.

A decline in pressure amplitude leads to an enhancement in production, so Ultra Low

Amplitude PPT waterflooding is supposed to produce better results in comparison with

Low Amplitude PPT. However, the test showed opposite results. The recovery factor

behavior during Ultra Low Amplitude PPT test is compared with RF behavior of four

previous tests conducted with 1020 cP oil in Figure 4.1.2.9. The Ultra Low Amplitude

PPT shows fewer enhancements in production in comparison with Low Amplitude PPT

and is around 6% less at the point where 3 PV were injected. Nevertheless, results of this

investigation are better than in case of High and Ultra High PPT – where all experimental

recovery factors remain higher.

94




Porosity, % 35




OOIP, cm3 34.1





95

Figure 4.1.2.9— Comparison of Effect of Ultra Low, Low, High, Ultra High Amplitude

PPT and traditional waterflooding on RF

0

10

20

30

40

50

60

0 0.5 1 1.5 2 2.5 3 3.5

RF

(%

OO

IP)

PV Injected



Ultra High amplitude PPT (Ex_9)

Low amplitude PPT (Ex_10)

Ultra Low Amplitude PPT (Ex_11)

96

The pressure jump coefficient of the pulses has a dramatic impact on production. Only

certain pulses can lead to a significant increase in oil production (Experiment 10 – Low

Amplitude PPT, Pressure jump coefficient 1.3÷1.6) , while the wrong properties of

pulsing can even lead to a lower recovery factor ( Experiment 9 – Ultra High Amplitude

PPT) than in the case of conventional oil displacement. In other words, to get the highest

recovery facto, during oil displacement implementing Pressure Pulsing Technology, it is

necessary to stay as close to Low Amplitude PPT, as it’s possible under external and

internal conditions.

97

4.2 Investigation Pressure Pulsing Technology impact on carbon dioxide (CO2)

injection. Influence of pulsing parameters on recovery.

4.2.1 Carbon dioxide (CO2) injection with following PPT (13707 cP heavy oil).

The process of conventional immiscible carbon dioxide flooding and immiscible CO2

flooding with PPT is experimentally investigated. According to published papers, the

solubility of CO2 in heavy oil is quit high (DeRuiter 1994). An increase in oil volume

occurs in the reservoir. This mechanism makes an important contribution, as residual oil

saturation is inversely proportional to the swelling factor (Klins and Farouq 1994).

Oil viscosity reduces significantly after CO2 saturates the reservoir oil. Laboratory

experiments show that higher reductions are observed in the more viscous oil (Dyer et al.

1994). Reductions in oil viscosity can lead to improved mobility ratio and increased

recovery factor.

This experiment was established as follows: Conventional CO2 flooding was conducted

300 minutes and after CO2 PPT. Also, heavy oil with 13707 cP was used and the model

was packed with sand Silica 530. CO2 was injected from a cylinder and the flow was

regulated by a Bronkhorst High-Tech Flow meter/controller. This Flow meter/controller

was factory calibrated for a specific gas, in this case Methane. The conversion factor was

calculated for CO2 injection. The calculation methodology was taken from the equipment

manual.

The main formula for determining the relationship between meter signal and mass flow

is:

Vsignal = K ⋅ cP ⋅Φm = K ⋅ cP ⋅ ρ ⋅ Φv (Eq. 4.2.1.1)

98

in which: Vsignal = output signal; K = constant; ρ = density; cP = specific heat; Φm = mass

flow; Φv = volume flow

From the previous equation, as soon as the cP value and density of the used gas changed,

the signal had to be corrected. The conversion factor C is:

(Eq. 4.2.1.2)

in which:

cP = specific heat

ρn = density at normal conditions

(1) gas calibrated ( in my case CH4)

(2) gas to be measured ( in my case CO2)

Specific heat (cP) and density at normal conditions (ρn) for methane and carbon dioxide

were acquired from a conversion table (see Appendix 1).

= 0.968 (Eq. 4.2.1.3)

As it was mentioned before, carbon dioxide is compressible and this means that pressure

changes will lead to volume change. To identify real flow rate under given conditions, the

Gas Formation Volume Factor is calculated. For this case, the Real Gas Equation was

used:

99

(Eq. 4.2.1.4)

where: Vgnc – gas volume at normal conditions

z – gas compressibility factor

n – moles of gas occupy the volume Vgnc

Tnc – normal temperature 20oC (293.15 K, 68

oF)

Pnc – normal pressure 1 atm (101.325 kN/m2, 101.325 kPa, 14.7 psi)

R – gas constant

For reservoir conditions, Equation 4.2.1.4 has the following form:

(Eq. 4.2.1.5)

where: Vgrc – gas volume at reservoir conditions

z – gas compressibility factor

n – moles of gas occupy the volume Vgnc

Trc – reservoir temperature (23oC; 296.15 K)

Prc – reservoir pressure (200 psi)

The Gas Formation Volume Factor is presented as:

(Eq. 4.2.1.6)

100

The next step of the calculation determines the gas compressibility factor z:

z = (0.4 lgTc+0.73) Pc

+0.1 Pc * (Eq. 4.2.1.7)

where: Tc and Pc are the critical temperature and pressure, respectively:

(Eq. 4.2.1.8)

(Eq. 4.2.1.9)

Coefficients A and B are found from formulas 4.2.1.10 and 4.2.1.11, given:

A= 94.717+17038 (Eq. 4.2.1.10)

B=4.892-0.4048 (Eq. 4.2.1.11)

Where is the density of carbon dioxide and is equal 1.98 kg/m3:

Substituting values for equations 4.2.1.6 – 4.2.1.11:

A= 94.717+1738 ·1.98 = 432.901 K (Eq. 4.2.1.12)

B= 4.892-0.4048·1.98 = 4.09 MPa (Eq. 4.2.1.13)

Now, knowing coefficients A and B we can calculate critical temperature and pressure:

Tc= 296.15/432.901 = 0.684 (Eq. 4.2.1.14)

Pc= 1.38/4.09 = 0.34 (Eq. 4.2.1.15)

Gas compressibility factor z is determined by Equation 4.2.1.7:

z = (0.4 lg 0.684+0.73)0.34

+0.1 0.34= 0.905 (Eq. 4.2.1.16)

* Eq. 4.2.1.7 – equation for calculation z factor, which has been widely used in Ukraine. Source: V.S.

Boiko, R.M. Kondrat, R.S. Jaremijchuk. Guide in petroleum industry. Lviv, 1996.

101

Finally, Gas Formation Volume Factor is calculated:

(Eq. 4.2.1.17)

Having calculated the Gas Formation Volume Factor Bg and conversion coefficient C, the

relationship between flow rate at the flow controller (2 mln/min) and mean flow rate of

carbon dioxide in the sand pack can be determined:

QCO2(rc)= QCH4(nc) ·C ·Bg (Eq. 4.2.1.18)

QCO2(rc)= 2 ·0.067 ·0.968 = 0.13 ml/min (Eq. 4.2.1.19)

Pressure pulsing was generated in the same way as it was performed in experiments with

water injection. In the laboratory setup, pulses were regulated by a valve with actuator

Hanbay® controlled by programmable electronic timer Omega®. CO2 injection was

established with a constant flow rate. While the valve was closed, pressure was

continuously increased and when the valve opened a pressure pulse was created.

As we know, CO2 is compressible gas and gas permeability is much higher than water

permeability. Also, during carbon dioxide injection, pressure fluctuated significantly after

implementation of PPT injection. The CO2 injection rate was set at the value 2.0 mln/min

of CH4 which is equal to 1.94 ml/min CO2. The absolute dependence of the pressure

accumulation versus time was set to the “close” position of the valve. Figure 4.2.1.1

shows the pressure increase behavior versus time. An equation describing the pressure

behavior relative to time was found:

P(t) = 0.1483 · t + 0.2671 (Eq. 4.2.1.20)

102

Where: P(t) – pressure at the moment t, psi

t – time from the beginning of injection, sec.

Experiment 12 – Carbon dioxide injection following Pressure Pulsing CO2 injection

(Period of pulsing – T=120 sec)

The model used for the research of CO2 injection and Pressure Pulsing Technology

during carbon dioxide injection, was the same as in the case of waterflooding. The same

materials were used for preparation of the sandpack and it was saturated with 13707 cP

heavy oil. A summary of this experiment and automatic valve settings are given in Table

4.2.1.1.

103

Figure 4.2.1.1— Dependence of pressure on time during pulsing generation

y = 0.1483x + 0.2671

0

10

20

30

40

50

60

70

80

90

0 100 200 300 400 500 600

Pre

ssu

re ,

psi

Time, sec

CO2 pressure Linear (CO2 pressure )

104




Porosity, % 31




OOIP, cm3 30.2

Injection Rate, cm3n/min 1.94



Absolute pulse pressure, psi 18.0

105

Gasses behave differently than liquids, with respect to pressure changes. CO2 is a

compressible gas and gas pulsing will have a different impact on the displacement

process than water pulsing, as water is an incompressible fluid. The influence of different

pulses are investigated and to determine the optimal parameters for pulsation.

The pressure behavior within a certain period of the experiment at the inlet of a sandpack

is given in Figure 4.2.1.2. From this Figure the pressure jumps from 0.5 psi up to almost

9 psi. The absolute pressure jump is 18 psi, which is twice as big. This is caused by high

gas permeability in the porous media and high gas compressibility.

From the beginning of the experiment, pure CO2 was injected. The recovery factor during

conventional injection had an active part and obtained a value around 12.5% and then oil

production sharply decreased. The second stage of the experiment involved PPT CO2

injection. As soon as PPT injection began, there was a significant increase in oil

production. This production enhancement is seen in the graph starting from 0.8 PV

injected. The recovery factor was sharply increased for another 0.5 PV, reached the value

of 17.5% and then stayed constantly low. By the end of experiment one cycle of PPT CO2

injection increased the recovery factor by approximately 4%.

106

Figure 4.2.1.2 – Pressure behavior at the inlet of the sandpack during PPT CO2 Injection

0

1

2

3

4

5

6

7

8

9

10

31050 31100 31150 31200 31250 31300 31350 31400

Pre

ssu

re,

psi

Time, sec

107

.


following PPT CO2 injection (T=120 sec)

0

2

4

6

8

10

12

14

16

0 0.5 1 1.5 2 2.5

RF

(%

OO

IP)

PV Injected

Conventional CO2 flooding PPT CO2 Flooding

3%

%

108

Experiment 13 – Carbon dioxide injection with following Pressure Pulsing CO2

injection (Period of pulsing – T=180 sec)

Experiment 24 was conducted to determine if Pressure Pulsing parameters had an impact

on production enhancement. As in Experiment 12, pulsations with a period of 120

seconds increased the recovery factor by 3%. In Experiment 13, the period between

pulsing was increased to 180 seconds (3 minutes).

The same preparation procedure was conducted and the main features of the model were

slightly different. The experiment was conducted under 200 psi of back pressure and a

temperature of 23 ºC. A short summary of the experiment is presented in Table 4.2.1.2.

Experiment 13 was conducted in two stages. The first stage covered conventional carbon

dioxide injection. This part of the test lasted until the point where 1.3 PV were injected.

Immediately after that, the second stage was started. During the second stage, CO2

injection with Pressure Pulsing was conducted and continued to the end of experiment

(2.5 PV injected). Pulsing was created every 3 minutes.

Results of traditional CO2 injection with following carbon dioxide injection with Pressure

Pulsing Technology are given in Figure 4.2.1.4. In this figure, there is an increase in the

recovery factor at the beginning of the experiment, but after ¼ of injected PV the increase

gradient declined and stayed constantly low. When 1.3 PV was injected, PPT CO2

injection was initiated. At this point, the second stage of the experiment began.

109




Porosity, % 31




OOIP, cm3 30.03





110



0

2

4

6

8

10

12

14

16

18

0 0.5 1 1.5 2 2.5 3

RF

(%

OO

IP)

PV Injected

CO2 CO2+PPT

2.0%

111

The effect of Pressure Pulsing Technology on the results are present in Figure 4.2.1.4.

PPT led to positive changes from the beginning of its implementation. From 1.3 to 2.1

PV injected, the recovery factor was raised from around 11.5% to around 15.0%. Then

the RF stayed constantly low and at 2.5 PV it reached a final recovery factor over 15.5%.

In total, Pressure Pulsing Technology with a pulsing period of 180 sec, increased the

recovery factor by about 2.0%.

Comparing results of Experiments 12 and 13, with period pulsing of 120 and 180

seconds, respectively, PPT showed an enhancement of 3% in Experiment 12 and

increased by 2.0% in Experiment. Shorter pulse periods led to slightly better results, but

this can also be caused by differences in models properties. Nevertheless, period and

pressure jump parameters have less impact in the case of CO2 injection in comparison

with water injection.


injection (Period of pulsing – T=60 sec)

From the results, even in spite of a small difference in the recovery factor, enhancement

of the pulsing parameters definitely has an impact on the displacement process. Pulsing

with a period of T=120 seconds gave better results than one with a period of T=180.

Hence, the need to investigate higher frequency pulsing. Pulsing with a period of T=60

seconds was investigated and the main features of this experiment are given in Table

4.2.1.3.

112




Porosity, % 33




OOIP, cm3 30.3





113

The model parameters remained close to the previous experiments. Carbon dioxide had

been injected from the beginning and was followed by CO2 injection with Pressure

Pulsing starting at 1.2 PV injected. PPT did not make any positive impact on oil recovery.

The recovery factor had a sharp increase from the beginning to 1 PV injected and, after

that, the oil cut and RF gradient decreased and remained low before and after PPT

implementation.

To summarize the results of this group of experiments, due to the compressibility of

carbon dioxide, pulses have a lesser impact than pulses during waterflooding. The time

between pulsing, with a constant flow rate regime, has to be much longer. For example,

in the case of water pulsing, the time period was 25 seconds for the highest RF and in the

case of CO2 injection, it was 120 seconds.

114



0

2

4

6

8

10

12

14

16

18

0 0.5 1 1.5 2 2.5

RF

(%

OO

IP)

PV Injected

Conventional CO2 injection CO2 injection + PPT

115

4.2.2 Ultra high flow rate carbon dioxide (CO2) injection with following PPT (13707 cP

heavy oil).

In this group of experiments the flow rate of carbon dioxide injection was sharply

increased. For previous experiments, the traditional flow rate (0.13 ml/min) was close to

1 ft/day in the field scale. For research purposes, a 1.94 ml/min flow rate of CO2 injection

was established. The experiments were conducted at normal conditions (T=20oC, P=14.7

psi). A back pressure regulator was not used.


injection (Period of pulsing – T= 60 sec)

An ultra high flow rate was established for conducting this test. This injected almost 40

PV of carbon dioxide during two stages: conventional CO2 injection and CO2 injection

with Pressure Pulsing Technology. Normal conditions were reached for conducting this

experiment. The preparation procedure and materials remained the same as in previous

experiments. The sand pack was saturated with 13707 cP heavy oil. A short summary of

the test is given in Table 4.2.2.1.

116




Porosity, % 33




OOIP, cm3 32.2





117


following PPT CO2 injection (T=60 sec) at ultra high flow rate

0

5

10

15

20

25

30

35

40

45

0 10 20 30 40 50 60

RF

(%

OO

IP)

PV Injected

Conventional CO2 Injection CO2 injection + PPT

`

8%

118

Traditional CO2 injection was lasted around 22 PV. The highest recovery factor was

recorded while the first 4 PV were injected (See Figure 4.2.2.1). After that, oil cut

decreased sharply and stayed constantly low until the second stage (Pressure Pulsing) was

started at 22 PV injected. For the first experiment in this group, I decided to use 60

seconds time period between pulses. Due to the high flow rate, as soon as PPT started, oil

cut increased significantly and the recovery factor enhancement are clearly seen in Figure

4.2.2.1 starting from the point 22 PV injected. By the end of the experiment, the RF

reached a value of around 42%. In total, the enhancement was approximately 8%. PPT

had a positive impact on oil cut, as it increased with implementation of the technology.

Even at the end of experiment, the oil cut was higher than it was before PPT, 0.5% and

0.4%, respectively (See Figure 4.2.2.2).

In general, the ultra high flow rate led to a high recovery factor and Pressure Pulsing

Technology had much more significant influence (8% enhancement) than in the case of a

regular flow rate (less than 5% enhancement)

Experiment 15 shows positive changes in oil displacement and the need to determine

optimal pulsing parameters arose so the next couple of experiments covered different

pressure pulsing parameters.

119

Figure 4.2.2.2 — Oil cut behavior during conventional CO2 injection with following PPT

CO2 injection (T=60 sec) at ultra high flow rate

0

2

4

6

8

10

12

14

16

18

20

0 10 20 30 40 50 60

Oil

cu

t, %

PV, Injected

Conventional CO2 injection CO2 injection +PPT

120



Experiment 16 is a logical continuation of this group of experiments. The pressure

pulsing period was increased three times and had a value of 180 seconds. From Figure

4.2.1.1 the absolute pulse pressure is equal to 27 psi. The preparation procedure and

experiment were conducted the same way as performed in Experiment 15. A summary of

this experiment is presented in Table 4.2.2.2.

The experiment was started with conventional carbon dioxide injection. At the beginning

of that stage (until 8 PV injected) oil cut and recovery factor were significantly high (See

Figure 4.2.2.3). After that both decreased sharply and stayed low. The oil cut was

fluctuating around 0.3%. At the point where 23 PV of CO2 was injected, carbon dioxide

was injected with Pressure Pulsing Technology. Initially, the enhancement was not

significant, but at 34 PV the recovery factor increased sharply and the oil cut reached a

maximum value of 2% (was 0.3% before PPT) at 51 PV injected. Both parameters

remained constantly low. By the end of Experiment 16, the Pressure Pulse recovery

factor was enhanced for around 17% and reached a total value of 56%.

After implementation of Pressure Pulsing, the pressure gradient within the sandpack

significantly changed and what was not typical for water or CO2 injection with PPT at a

regular flow rate. Data from three transducers before and during PPT are plotted in

Figure 4.4.2.4. Transducer #1 was located at the inlet of the sand pack. Transducers #2

and #3 are located within a sand pack 67.5 mm from the inlet and outlet, respectively,

and the distance between them was 150 mm (See Figures 3.1 and 3.3).

121

In Figure 4.4.2.4, before Pressure Pulsing implementation, the pressure gradient was

constant and slightly declining with time. The average injection pressure (transducer #1)

was less than 12 psi. After PPT started, the pressure tendency changed from decreasing to

increasing and at 35 PV, it reached its maximum – over 25 psi. After the pick there is a

slight decline in injection pressure to approximately 17 psi and an increase to around 22

psi at 51 PV injected. Later, the pressure gradient decreased. Transducers #2 and #3

showed similar pressure gradient behavior. The difference in values was caused by

transducer location.

If the recovery factor graph, oil cut trend and pressure behavior graph are compared, it

appears each increase in the average pressure gradient leads to an increase in oil cut and

recovery factor.

A pressure increase is explained by CO2 irregular flow created with pulsing. Pressure

Pulsing gas had already made channeling inside the sandpack after breakthrough and this

was a cause of low oil cut and recovery factor, as carbon dioxide flow mainly occurred

through the channeling, leaving oil saturated regions behind. With pulsation, CO2 was

pushed to new pores, as channel conductivity was not high enough to let much higher

amounts of gas, created by pulses, to pass through. Oil from newly impacted pores

moved and partly blocked previously created channels. All the actions made gas flow to

cover more pore volume and increase sweep efficiency.

122




Porosity, % 31




OOIP, cm3 30.2





123



0

10

20

30

40

50

60

0 10 20 30 40 50 60

RF

(%

OO

IP)

PV Injected

Series1 Series2

17%

CO2 CO2 +PPT

124

Figure 4.2.2.4 — Pressure behavior during conventional CO2 injection with following PPT CO2 injection (T=180 sec) at ultra high

flow rate

0

5

10

15

20

25

30

35

40

45

20 25 30 35 40 45 50 55

Pre

ssu

re,

psi

PV Injected

Transducer #1 Transduser #2 Transducer #3

125



With regard to the results of Experiments 16 and 17, an increase in pulse period (T) and

pressure of the pulse leads to an enhancement of the recovery factor. In Experiment 15,

the pulse period was 60 seconds and the recovery factor enhancement 8% and in

Experiment 16 – 180 seconds and 17%, respectively. Under this circumstance, the

decision was made to increase the period to 300 seconds. From Figure 4.2.1.1, the

absolute pulse pressure is 45 psi for a time 300 seconds.

As the current experiment was conducted under the Ultra high flow rate group of

experiments, the physical parameters of the model were close to the parameters of the

two previous investigations in this group. The main model parameters are listed in Table

4.2.2.3.

The procedure was quite similar to Experiments 15 and 16. For 18 PV injected,

conventional carbon dioxide injection occurred. Then Pressure Pulsing Technology was

implemented. The RF had a very close trend to experiments with a pulsing period of

T=60 and T=180 seconds. PPT made a positive impact on oil recovery from the very

beginning. First, there was a slight enhancement and at 38 PV injected there was a track

sharp increase in the recovery factor (See Figure 4.2.2.5). This significant enhancement

lasted until 45 PV and then the RF gradient stabilized at levels close to those during

traditional CO2 injection. In total, the recovery factor enhancement was 12.5%. This

value is lower than in the case of Experiment 16 (T=180 sec) 17%. Nevertheless, this

result was better than in Experiment 15 (T=60 sec) with an 8% enhancement.

126




Porosity, % 31




OOIP, cm3 30.3





127



0

5

10

15

20

25

30

35

40

45

50

0 10 20 30 40 50 60

RF

(%

OO

IP)

PV Injected

Conventional CO2 Injection CO2 Injection + PPT

12.5%

128

The Ultra High Flow rate CO2 injection with Pressure Pulsing Technology can lead to a

total recovery factor of up to more than 50% while regular flow rate carbon dioxide

injection with PPT provides a RF less than 16% for a similar period of time. PPT has the

best impact on RF with the following parameters: T= 180 sec and absolute pulse pressure

27 psi. As in the case of water injection with PPT, pulsing parameters have a significant

impact on the displacement process. Only the correct pulsing parameters can lead to

success.

129

4.3 Investigation Pressure Pulsing Technology impact on WAG displacement

4.3.1 Continuous CO2-WAG Flooding

The main types of WAG are: Continuous, tapered, and simple WAG injections are based

on slug sizes and water-gas ratios.

Continuous WAG process - large slug of the gas is followed by waterflooding.

Simple WAG - a number of small slugs of gas and water injected one by one.

Tapered WAG process - gas and water slugs of decreasing volume are subsequently

injected after each injection cycle.

Experiment 18 –CO2-WAG Flooding. Five stages heavy oil displacement. (CO2

injection -> CO2 injection with PPT -> waterflooding -> waterflooding with PPT ->

CO2 injection)

Continuous carbon dioxide WAG flooding was conducted in this experiment. In total,

five stages of injection were carried out. 13707 cP heavy oil was used for sandpack

saturation. Conventional CO2 flooding at the beginning of the investigation was followed

by carbon dioxide injection with Pressure Pulsing Technology. Then water was injected

traditionally and with pressure pulsing. The experiment was finished with conventional

carbon dioxide injection. The main experiment features are listed in Table 4.3.1.1. A

detailed description of each stage is given in Figure 4.3.1.1.

130

Stage 1 – Conventional CO2 injection

The primer type for heavy oil displacement was conventional carbon dioxide

injection. It led to high oil recovery before breakthrough, but by the time 0.5 PV

was injected, oil cut decreased sharply and remain constantly low (less than 3%),

until the second stage was started at 0.8 PV.

Stage 2 – CO2 injection with Pressure Pulsing Technology

During the second stage, gas was injected with pulsation. The pulsing period was

120 seconds, as due to previous experiments this period was the most effective.

CO2 pulsations showed a positive impact on results. At the beginning of PPT, the

oil cut increased to 5 % but at 1.6 PV injected it declined again to 1%. Gas

pulsation led to around a 2-3% production enhancement. Stage two was followed

by traditional waterflooding.

Stage 3 – Conventional waterflooding

To decline residual oil saturation water was injected. Waterflooding led to a sharp

increase in the recovery factor. From 1.6 to 2.4 PV injected, the recovery factor

changed from 12 to almost 29%. At the beginning of this stage, oil cut was

increased from 1 to 24%. But after 2.4 PV, oil cut declined to 11% and at 2.6 PV

it was already 3%. At this point pulsation was started.

Stage 4 – Water flooding with Pressure Pulsing Technology

Water injection with PPT was conducted from 2.6 to 3.4 PV. Pulsation parameters

were chosen due to the recommendation made in section 4.2.1. Low amplitude

131

Pressure Pulsing was implemented. In general, pulses did not show any changes

in RF trend. This fact proves the results of Experiment 1.1, where PPT did not

have any positive impact on residual oil saturation during the late stage of

development. Oil cut slowly declined during this period from 3 to 2%.

Waterflooding with PPT was followed by conventional carbon dioxide injection.

Stage 5 – Conventional CO2 Injection

During last Stage 5, carbon dioxide was traditionally injected. The injection lasted

from 3.5 to a little over 4 PV. Repeated gas injection had a positive impact at the

beginning of the stage. Oil cut increased from 2 to 5%, but shortly after that, it

decreased to the value of 1%.

In total, continuous CO2 -WAG flooding, with primer carbon dioxide injection, led to a

recovery factor of almost 35% at 4 PV injected. In comparison with conventional

waterflooding (Experiment 1) it is around 4% more.

132




Porosity, % 32




OOIP, cm3 30.9

Injection Rate, cm3/min

Water 0.13

CO2

0.13

Period of pulsing (T), sec Water 25

CO2 120


133

Figure 4.3.1.1 — Recovery factor behavior during continuous CO2 WAG with PPT

0

5

10

15

20

25

30

35

40

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5

RF

(%

OO

IP)

PV, Injected

CO2 injection

CO2 injection+PPT

Water injection

Water injection+PPT

CO2 injection

134

Experiment 19 –CO2-WAG Flooding. Five stages heavy oil displacement.

(waterflooding -> waterflooding with PPT ->CO2 injection -> CO2 injection with

PPT -> waterflooding)

Experiment 19 was conducted in five stages, including PPT, to get the maximum oil

recovery. A short summary of the experiment is given in Table 4.3.1.1. This experiment

is opposite to Experiment 18, as the entire procedure started with water flooding and

Experiment 18 - with gas injection.

Stage 1- Conventional water injection

The experiment started with conventional waterflooding and lasted approximately

1 PV injected. The injection rate was 0.13 cm3/min. This stage is characterized by

a high recovery factor at the beginning of injection and but still significant at the

end. Basically, the stage has all features of conventional waterflooding.

Stage 2 – Water Injection with Pressure Pulsing Technology

After regular waterflooding (Stage 1) waterflooding was conducted with Pressure

Pulsing Technology. Pulsing parameters were chosen from the results of section

4.1. The timer was set for a 25 second period (Low amplitude PPT). This

injection lasted another 1.4 PV. From Figure 4.3.1.1, Pressure Pulsing did not lead

to production enhancement. The results are very similar to Experiment 1, water

injection with PPT did not make any positive impact on residual oil saturation.

135

Stage 3 – Conventional carbon dioxide injection

During this stage carbon dioxide was injected with a constant flow rate of 0.13

cm3/min. The injection was started at 2.4 PV injected and was conducted to 3.3

PV injected. At the beginning, only a slight RF increase was noticed, but it

became more significant after 3 PV injected and then decreased. Conventional

carbon dioxide injection ended at 3.3 PV with a total RF of 32%.

Stage 4 - Carbon dioxide injection with Pressure Pulsing Technology

At the end of conventional CO2 injection, the oil cut decreased sharply (from over

5% at the beginning of Stage 3 to less than 2%) and pulsation was started. At first,

Pressure Pulsing did not show enhancement and oil cut continued to decline and

reached the bottom value of 0.5% at 3.8 PV injected. This period is represented in

Figure 4.3.1.1 with a horizontal line. Nevertheless, PPT made it contribution and

the oil cut increased to 1.3% and RF to 33% until the end of this stage.

Stage 5- Conventional water injection

At the end of CO2 injection with pressure pulsation, the RF was only around 32%

After gas injection and gas injection with PPT, waterflooding led to a significant

enhancement in production. From Figure 4.3.1.1, with the beginning (4.3 PV

injected) of water injection, the recovery factor increased sharply. Oil cut also

increased from 1.3 to 5.3% and reached the pick of 8.8% at 5.4 PV and the RF

136

and oil cut decreased. The experiment continued until almost 6 PV were injected.

By the end of experiment, the recovery factor reached the value of 42%.

The results of Experiment 36 and Experiment 1 can be compared. The experimental

models were saturated with 13707 cP oil. During traditional waterflooding, similar

amounts of water were injected. As it was mentioned before, WAG displacement resulted

in 43% oil recovery, while conventional waterflooding was only 33%.

In the CO2 WAG process, WAG was more effective with primer water injection, as the

last stage of this experiment showed a sharp production enhancement while in

Experiment 18 an increase in oil production was not significant.

137




Porosity, % 32




OOIP, cm3 30.9


Water 0.13

CO2

0.13


CO2 120


138

Figure 4.3.1.2 — Recovery factor behavior during continuous CO2 WAG with PPT

0

5

10

15

20

25

30

35

40

45

0 1 2 3 4 5 6 7

RF

(%

OO

IP)

PV Injected

Water injection

Water injection + PPT

Gas Injection

Gas Injection + PPT

Water injection

139

4.3.2 Simple CO2-WAG Flooding

Fluids were injected at the same injection rate of 0.13 cm3/min. The slug size was 10% of

PV. The slug ratio was 1:1. According to the literature the parameters were the most

common this category of experiment(Randal and Brush/William 2000); (Torabi and

Jamaloei 2010). A 1:1 WAG ratio is the most common in the field projects (Christensen

and Stenby 2001); (Fulop and Biro 1997). Injection started with a 10% of PV slug of

water followed by a 10% of PV slug of CO2. Then, 10% of PV of water was injected

followed by a slug of carbon dioxide. The experiment was performed until a negligible

amount of oil was produced.

Experiment 20 – Conventional CO2-WAG Flooding

There were two objectives for conducting conventional carbon dioxide WAG flooding.

First, the objective was to determine the efficiency of the WAG process and to compare it

with traditional CO2 or waterflooding. The second objective was to set the base line for

future experiment that would cover WAG injection with Pressure Pulsing Technology.

The experiment was started with a slug of water that was followed by a slug of CO2 and

so on. A short summary of the experiment is given in Table 4.3.2.1.

In Figure 4.3.2.1, the results of this experiment are compared with the results of

conventional waterflooding. From the beginning of the WAG process, there was no

production enhancement. Moreover, the recovery factor for traditional waterflooding was

significantly higher. At the point where 1.5 PV was injected, the difference became over

5% on behalf of waterflooding. Nevertheless, from that point WAG recovery factor

began increasing significantly and, at 2.1 PV, crossed the water injection trend with a

140

high positive gradient. The sharp production enhancement led to a recovery factor of

almost 38% until the point where 3.3 PV were injected. The oil cut was quite at 5.9%,

while for waterflooding this value was less than 1%.

In general, production enhancement at 3.3 PV injected was over 7%. An important fact is

that oil cut was significant too and further WAG displacement would lead to a larger

difference in the recovery factors.

141




Porosity, % 34




OOIP, cm3 30.9


Water 0.13

CO2

0.13

142

Figure 4.3.2.1 – Recovery factor comparison: WAG vs Conventional waterflooding

0

5

10

15

20

25

30

35

40

0 0.5 1 1.5 2 2.5 3 3.5 4

RF

(%

OO

IP)

PV Injected

Simple CO2 WAG

Traditional waterflood (Ex_11) 1

143

Experiment 21 - CO2-WAG Flooding with Pressure Pulsing Technology

WAG flooding with pulsing was conducted during Experiment 21 simple CO2. The slug

size was 10% of PV and the slug ratio was 1:1, as it was in Experiment 20. The

displacement process was started by a 10% of PV slug of water injection with PPT and

was followed by a 10% of PV slug of carbon dioxide injection with PPT.

The pulsing parameters for water and CO2 injection were different. As it was performed

before, the period of pulsation was chosen from previous experimental experience with a

water injection period of T = 25 seconds and for gas injection of T=120 seconds. The

main features of the experiment are listed in Table 4.3.2.2.

The results of this experiment showed a significant enhancement in oil production. The

recovery factor behavior is evident in Figure 4.3.2.2. In general, during the experiment,

the RF remained at a high level. A small delay in production enhancement was observed

from 0.1 to 0.8 PV injected. In total, at 3 PV injected RF reached the value of almost

45%. Oil cut still remained quite high on the level of 7.4%. Oil cut in the WAG process

was 7.4%, while during traditional water injection it was less than 1%.

Comparing traditional carbon dioxide WAG and CO2 WAG with Pressure Pulsing

Technology, it is evident in Figure 4.3.2.2 that pulsation lessens the production

enhancement delay zone at the beginning and exceeds the conventional CO2 WAG

process by around 8% where the oil cut remained 1.5% higher.

144




Porosity, % 33




OOIP, cm3 32.3


Water 0.13

CO2

0.13


CO2 120


145

Figure 4.3.2.2 — Recovery factor behavior during simple CO2 WAG with PPT

0

5

10

15

20

25

30

35

40

45

50

0 0.5 1 1.5 2 2.5 3 3.5 4

RF

(%

OO

IP)

PV Injected

Simple CO2 WAG

Simple CO2 WAG with PPT

Traditional waterflood (Ex_11) 1

146

4.4. Investigation of heavy oil displacement by Pressure Pulsing Technology using a

micro model.

LaserCut 5.3® software was used for designing current model pattern. This glass micro-

model was constructed based on laser etched methodology. The heterogeneous glass

micro-model used in this group of experiment was a representation of sandstone porous

media. Sizes of pores were in the range of 316 to 1483 micrometers and diameters of

throats were in the range of 70 to 490 micrometers. Grain diameters fluctuated in range of

794 to 2592 micrometers. The model had features of significant heterogeneity. Pattern of

the micro model is presented in Figure 4.4.1. Other top glass part was optically flat then it

was placed over the first one. In this scenario top glass was covering the etched pattern

and creating pore space. In the cover plate two holes at the end were drilled: Inlet and

outlet. Both plates together were horizontally placed into a special oven where

temperature and heat flux controlled automatically what enabled them to fuse. The fusion

process was performed to achieve completely sealed model and to eliminate liquid flow

over structure grains. Length of the micro-model was 160mm and width was 40mm.

147

Table 4.4.1 - Physical and hydraulic properties of micro-model pattern

Dimensions (mm×mm) 40x160

Pore diameter (μm) 316-1483

Throat Diameter (μm) 70-490

Grain diameter (μm) 794-2592

Pore volume (ml) 0.49

148

Figure 4.4.1 – Glass micro model pattern

149

To get a clear picture of a displacement process inside the model, an additional light

source was used. It was placed a couple inches under the model. For a more uniform

distribution of the light, a light diffuser was placed directly under the micromodel.

Picture capturing was performed with a digital camera installed above the glass model.

Figure 4.4.2 presents a schematic diagram of the experimental set-up with the micro

model.

Before each experiment, the light source, diffusion glass and the model were examined to

ensure they were absolutely clean, as spots could lead to inaccurate visual observations.

To record the pressure drop during the displacement process, one transducer was

connected at the inlet and one at the outlet. Data from the transducer was collected on a

computer.

After each experiment, the model was cleaned by injecting toluene following an injection

of DI water. When the model looked completely clean, it was dried out by injecting

warmed nitrogen.

At the beginning of the experiment, the micromodel was saturated with the aqueous

phase and the aqueous phase was displaced by oil. Hence, the model was saturated with

oil and connate water.

For clearer observations, porous media and oil in the aqueous phase had been colored in

blue and the oil had a natural black color.

150

Figure 4.4.2- Schematic diagram of the experimental set-up with micro model

LEGEND

- Three-way valve

- Two way valve

- Four way connection

- Three way connection

- Electronic pressure gauge

- 1/8 pressure line

- Data cable

- Boundaries of the air bath

1

4

5 6

7

8

9

12 13

14

3

10

73

11

15 16

3

1 – syringe pump

2 – CO2 cylinder

3 – check valve

4 – personal computer

5 – transfer cylinder

6 – pressure accumulator

7 – controlled solenoid

valve

8 – transducer #1

9 – digital camera

10 – glass micromodel

11 – source of light

12 – manual pressure regulator

13 – N2 cylinder

14 – diffusion glass

12 2

17

18

19

20

21

15 – back pressure regulator

16 – test tube

17 – flow meter/controller

18 – temperature sensor

19 – heater element

20 – temperature controller

21 – power cord

151

Pore volume measurements were made at the beginning of the experiments. For this

reason, the model was vacuumed and then brine was injected with high accuracy. All air

bubbles were extracted with a vacuum pump and the model was filled with brine. The

measured pore volume was 0.49 ml after the procedure,.

The first couple of experiments covered conventional waterflooding. As the PV was quite

small, the injection flow rate was chosen to be 0.01 ml/min. Then a group of waterfloods

with different periods of pulsation were conducted.

Experiment 22 - PPT Waterflooding with 25 seconds period

From the previous experiments, the best results were achieved by implementing low

amplitude Pressure Pulsing Technology. This is why the period of pulsation was chosen

to be 25 seconds for the first waterflooding with PPT.

The first pictures were taken at time point 1 minute from the start of the displacement

process. In both cases, viscous fingering was significant. The similarity between

conventional waterflooding and PPT waterflooding is explained by a short time step, as

only two pulses occurred during the first minute.

The following observation time was 30 minutes or 29 minutes. During water injection

with PPT, water flow spread more uniformly in the model, and in the case of

conventional waterflooding, water flow was mainly concentrated in one part of the model

(Figure 4.4.3(1) c and d).

152

a)

b)

c)

d)

Figure 4.4.3(1) - Results of PPT waterflooding with pulsing period 25 sec.a, b - micro



respectively.

NO WATER REGION

1 min

1 min

30 min

30 min

153

The following model capture was performed at 60 and 120 minutes (See Figure 4.4.3(2)).

At the 60 min point during conventional waterflooding, the "now water zone" decreased.

During PPT waterflooding, the zones could only be located at the edge of the model.

Parts of the model were not affected by water and highlighted by a yellow line.

By the end of the experiment (t=120min), most of the model area had been flooded by

water. Nevertheless, oil cut in place still remained high. Comparing capture c) and d) in

case of traditional waterflooding, sweep efficiency was lower than in the case of PPT

water injection. PPT definitely has a positive impact on oil displacement.

154

a)

b)

c)

d)



micro model at time 120 minutes during conventional and PPT waterflooding

respectively.

NO WATER REGION

60 min

60 min

120 min

120 min

155


According to the experimental results, increasing the pulsation period leads to a decline

in oil production. To prove this statement in the current experiment, the period of

pulsation was set to 60 seconds (1 minute). This was more than twice as long as in the

previous experiment (25 sec). The flow rate was set at a constant value of 0.01 ml/min.

From Figure 4.4.4(1): pictures a) and b), PPT with a period of one minute leads to a

faster breakthrough, as the one minute flow during PPT injection water had already

reached the outlet and, during conventional waterflooding, water had gone through 6/7 of

the length of the porous media. The traditional water flow was wider than the PPT flow.

Pictures c) and d) depict the PPT impact at 30 minutes after the displacement process.

Conventional waterflooding creates a big “water free area” and PPT leads to a more

uniform distribution of water in the model, but separate oil zones of significant size are

bypassed by water. In both cases, significant amounts of oil were trapped.

Picture capture was performed at 60 and 120 minutes (See Figure 4.4.4(2)). Starting from

the 60 min point Pressure Pulsing displacement gave slightly better results than the

traditional one. Trapped oil zones shrank and more oil was displaced. Improved sweep

efficiency is explained by an increased number of pulsations that occurred by that time.

By the end of the experiment, at the 120 minutes point, PPT injection was noticeably

overcome by conventional waterflooding, as seen in pictures c) and d).

156

a)

b)

c)

d)




respectively.

NO WATER REGION

1 min

1 min

30 min

30 min

157

a)

b)

c)

d)




respectively.

NO WATER REGION

60 min

60 min

120 min

120 min

158


High Amplitude Pressure Pulsing waterflooding was conducted within 120 second time

periods, which means the pulsation period was doubled in comparison with the previous

experiment. The flow rate remained constant at 0.01 ml/min.

Due to a large pulsing time step, during the first minute of the displacement process, no

pulsing occurred and this is why pictures a) and b) in Figure 4.4.5(1) were captured after

2 minutes and not after the first minute, as it had been performed before. However,only

one pulse was recorded during the first two minutes.

By comparison with pictures a) and b) from Figure 4.4.5(1), the pulsation led to an

enhancement of the displacement process, as water flow covered a larger area,

breakthrough did not occur and during the conventional waterflooding the water reached

the outlet.

Another tendency was observed in the picture taken at 30, 60 and 120 minute time points

(See Figure 4.4.5(1) and 4.4.5(2)). Starting from the 30 minute pictures, the traditional

waterflooding gave a better sweep efficiency than displacement with pulsation. The main

"water free" zones or area with trapped oil is highlighted with a yellow line.

By the end of the experiment, PPT waterflooding led to an increase in water coverage of

the model area, but conventional waterflooding had a higher displacement efficiency. The

results obtained from the experiments conducted in the sandpack have been proven by the

glass micromodel experiments.

159

a)

b)

c)

d)



model at 30 minutes during conventional and PPT waterflooding, respectively.

NO WATER REGION

2 min

2 min

30 min

30 min

160

a)

b)

c)

d)



model at 120 minutes during conventional and PPT waterflooding, respectively.

NO WATER REGION

60 min

60 min

120 min

120 min

161

CHAPTER FIVE: CONCLUSIONS AND RECOMMENDATIONS

5.1 Conclusions

A detailed literature review was performed and over twenty laboratory experiments were

successfully conducted. The following conclusions are made:

- The number of research projects is quite limited but Pressure Pulsing Technology

has been successfully used in a field. This thesis may have significant role in the

development of current technology, as new approaches have been investigated.

Namely, PPT waterflooding in a porous media saturated by 13 707 cP heavy oil;

PPT during carbon dioxide injection; PPT CO2 injection with ultra high flow rate;

and PPT waterflooding in a glass micromodel.

- The results of the waterflooding experiments showed that the effect of Pressure

Pulsing Technology closely depends on pulsation parameters: Pressure amplitude,

period or frequency. Low Amplitude PPT led to the highest recovery factor. The

last one was increased from 30 to 38% of OOIP with 13707 cP of oil and from 42

to 51% with 1020 cP of oil.

- Due to the compressibility of carbon dioxide, Pressure Pulsing Technology had a

weaker impact than pulses during waterflooding. The pulsing period, with a

constant flow rate regime, had to be much longer. For example, in the case of

water pulsing, the time period was 25 seconds for the highest RF and in the case

of CO2 injection, it was 120 seconds and a 3% enhancement was recorded.

- Pressure pulsing led to significant production improvements during Ultra High

Flow rate CO2 injection. All three runs were successful. The experiment with a

pulsing period of 180 sec led to a 17% increase in the recovery factor.

162

- According to the continuous WAG displacement processes, PPT did not have a

substantive influence. During simple WAG with PPT, an 8% increase in RF over

traditional CO2 WAG was observed and the experimental oil cut was 1.5% higher

than in the case of traditional WAG.

- Experiments with a glass micromodel made it possible to see the fluid flow

behavior in porous media and the impact of PPT. The results conducted in the

sandpack were proven by the micromodel experiments.

163

5.2 Recommendations

The following recommendations are proposed for future work:

- To implement Pressure Pulsing Technology during computer simulations of water

or CO2 injection and compare the results with laboratory data.

- Use a mathematical approach to discover analytical expressions describing

relationships between pulsing parameters, oil properties and properties of

injecting agents.

- To conduct a series of experiments using different type of injecting gas (Propane,

methane, nitrogen...).

- To experiment with Pressure Pulsing Technology and different types surfactant

and polymers.

- WAG injection with PPT requires more research as the impact of slug ratio, slug

size.

- Experiments at a larger scale (3D models or field pilot projects) may show more

accurate and reliable results.

164

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169

APPENDIX A

GAS CONVERSION TABLE

170

171

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