ghayas final project report

1

“SIMULATION OF A SAGD

RESERVOIR”

A FINAL YEAR PROJECT SUBMITTED TO THE DEPARTMENT OF

THE CIVIL AND ENVIRONMENTAL ENGINEERING OF

UNIVERSITY OF ALBERTA IN PARTIAL FULLFILLMENT OF THE

REQUIREMENTS FOR THE DEGREE OF MASTERS

GHAYAS QAMAR

SEPTEMBER 2012

2

ABSTRACT

A huge quantity of bitumen reserves and heavy oil are present worldwide. These reserves have

been estimated to be 85% of the total conventional crude oil in place and are present only in

Canada and Venezuela. 1.7 trillion barrels of original heavy oil in place is present in Canada. So,

Oil sands deposits recovery requires efficient and cost effective viscosity reduction techniques so

that huge quantity of heavy oil and bitumen reserves in the world can be produced.

Model on first stages of the steam-assisted gravity drainage (SAGD) process were carried out,

using three-dimensional (3D) scaled reservoir models, to investigate production process and

performance of the heavy oil reservoir. The project is CMG based model and precisely defined

with certain geometry. STARS is used as a SAGD reservoir simulator in this project and step by

step procedure is shown and discussed. Initially the model is run and simulated with the use of

heavy oil fluid properties in CMG. Afterwards the same model is run many times by changing

different parameters and results are compared accordingly.

3

ACKNOWLEDGEMENT

I take immense pleasure in thanking Dr. Alireza Nouri, Associate professor for having permitted

me to carry out this project work. I wish to express my deep sense of gratitude to my internal

guide, Mr. Ehsan Rahmati, PhD student with Dr. Alireza Nouri for his able guidance and useful

suggestions, which helped me in completing the project work, in time. Words are inadequate in

offering my thanks to both of them for their encouragement and cooperation in carrying out the

project work. Finally, yet importantly, I would like to express my heartfelt thanks to my beloved

parents for their blessings, my friends/classmates for their help and wishes for the successful

completion of this project.

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LIST OF TABLES

TABLE 1 IMPORTANT RESERVOIR PARAMETERS FOR MODELLING.

TABLE 2 RESERVOIR PROPERTIES

TABLE 3 REFERENCE CONDITION

TABLE 4 RELATIVE PERMEABILTY VALUES


5

LIST OF FIGURES

Figure 2.1 SCHEMATIC OF SAGD WITH TWO HORIZIONTAL WELLS

Figure 2.2 HOT FINGERING IN SAGD

Figure 2.3 HORIZONTAL WELL CONFIGURATIONS

Figure 3.1 SCHEMATIC VIEW OF THE FIELD

Figure 4.1 RESERVOIR MODEL

Figure 4.2 PLOT BETWEEN BW AND PRESSURE

Figure 4.3 PLOT BETWEEN WATER DENSITY AND PRESSURE

Figure 4.4 RELATIVE PERMEABILITY CURVES 1

Figure 4.5 RELATIVE PERMEABILITY CURVES 2

Figure 4.6 STONE RELATIVE PERMEABILITY MODEL

Figure 5.1 PLOT BETWEEN CUMMULATIVE OIL AND TIME (BASE CASE)

Figure 5.2 PLOT BETWEEN CUMMULATIVE OIL AND TIME (ALTERNATE CASE 1)





Figure 5.7 PLOTS SHOWING ALL CONSTRAINS

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TABLE OF CONTENTS

Abstract .................................................................................................................. ..........1

Acknowledgement .................................................................................................. .........2

List of Table ........................................................................................................... .........3

List of Figures ....................................................................................................... ..........4

Chapter 1

Introduction ......................................................................................................... .........8

1.1 Objective ............................................................................................... .........9

Chapter 2 ....................................................................................................... ..........10

Steam Assisted Gravity Drainage.............................................................................10

2.1 General Overview of SAGD ............................................................. ..........10

2.2 Start Up ............................................................................................... ..........12

2.3 Break through Time ............................................................................ ..........13

2.4 Growing phase .................................................................................... ..........13

2.5 Effect of Steam Chamber pressure ..................................................... ..........14

2.6 Spacing Between Wells Pair ............................................................... ..........14

2.7 Length of Horizontal Wells ................................................................ ...........14

2.8 Well Configuration ............................................................................. ...........15

2.9 Well Placement ................................................................................... ...........15

7

2.10 Process Characteristics........................................................................ ..........16

2.11 Advantages .......................................................................................... ..........17

2.12 Limitations .......................................................................................... ..........17

Chapter 3 ......................................................................................................... ........18

Efficiency of SAGD ............................................................................................ ........18

3.1 Expansion of horizontal Sweep Volume .............................................. ........19

3.2 Increasing Mobility ............................................................................... ........19

3.3 Control of Steam injection rate ............................................................. ........19

Chapter 4 ....................................................................................................... ..........20

Modelling of SAGD reservoir..................................................................................20

4.1 Computer Modelling Group............................................................. ... ..........20

4.2 IMEX .................................................................................................. ..........20

4.3 GEM .................................................................................................... ..........21

4.4 STARS ................................................................................................ ..........21

4.5 Description of Reservoir ..................................................................... ..........22

4.6 SAGD model on STARS .................................................................... ..........22

4.3 Make of A Model ................................................................................ ......... 24

8

Chapter 5 ....................................................................................................... ........43

Effect of Injection Parameters on SAGD...............................................................43

5.1 Base Case ............................................................. ............................. ........43

5.2 Alternate Case 1 .................................................................................. ........44

5.3 Alternate Case 2............................................................. ..................... ........45

5.4 Alternate Case 3 .................................................................................. ........46

5.5 Alternate Case 4 .................................................................................. ........48

5.6 Alternate Case 5 .................................................................................. ........49

5.7 Cumulative Effect ................................................................................ ........49

Chapter 6.........................................................................................................51

Discussion & Conclusion………………………………………………......................51

8.1 Discussion…………………………………………………………............51

8.2 Conclusion………………………………………………………...............51

REFERENCES....................................................................................................52

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CHAPTER 1

INTRODUCTION:

Over 300 billion barrel of the estimated oil in place is placed in the oil sands with none appearing

to be recoverable by natural flow. A well was drilled into the oil sands formation in 1900 and

then it was re-drilled in 1957 and it was found that about 30 ft of tar-like oil was found to have

accumulated in the hole. In order to extract these heavy reserves of oil from the surface, various

kinds of enhanced oil recovery techniques were used (1).

However the technique that gives us the

best cumulative oil production and was more economical was SAGD.

SAGD is a special form of systematic steam drive that uses at least one horizontal injector and

horizontal producer. In some of the case it can also use one horizontal production well and one

horizontal or several vertical injection wells located above the horizontal production well. Steam

is injected through the injection well and it expands the steam chamber. Steam heats the oil and

condenses at the perimeter of the chamber (2).

The production is taken from the production well

as the oil drains and falls under the effect of gravity. SAGD process is also known as a Gravity

Drainage Process.

The physics of the Steam-assisted Gravity Drainage (SAGD) process is so complex that both

physical and numerical modelling analysis should be used as complementary tools in order to

obtain the insight into different mechanisms of the operation and also to determine the strategies

that will optimize the process. Understanding of the reservoir process can improve immensely by

using both the physical as well as the numerical models. Physical model helps us to check the

accuracy and the assumptions that can be used in the numerical modelling .History matching can

be used to validate the accuracy of the numerical model (2)

.

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OBJECTIVE

The objective of this study is to model SAGD reservoir using CMG software to perform

simulation of the SAGD reservoir using heavy oil fluid properties. Moreover, the results of the

base model are compared with other alternative cases in order to compare the injection

parameters of SAGD model. The model consists of twin horizontal wells as one injector and one

producer with certain distance apart. In order to build a SAGD model, a thorough concept of

SAGD reservoir is discussed before the making of a model. Efficiency of SAGD reservoir is also

our focus in this study and factors affecting efficiency of SAGD are briefly discussed.

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CHAPTER 2

STEAM ASSISTED GRAVITY DRAINAGE

This chapter will present a comprehensive review of the important aspects to understand the

SAGD recovery process. It includes its introduction, start up procedure, Steam Chamber growing

phase, Process characteristics, Well configuration, Well completions, advantages and some

field’s examples.

Since 1960’s Canada crude oil reserves have been declining rapidly .At the same time, it is very

costly to develop Canadian offshore ventures. In order to fulfill the country’s requirement it is

very important to extract the heavy oil from the Athabasca region located in Alberta. Athabasca

oil sands contain deposits up to 140 billion cubic meters cubic meters or one trillion barrels of

original bitumen-in-place and span up to 40,000 square kilometers. It is located in the northern

part of Alberta. This amount comprises two-thirds of Alberta’s total oil reserves and 20% of

Canada’s (3).

Last thirty years shows that the Canada total annual oil production have increased from 2% to 30

%. Syncrude Canada Ltd. and Suncor Inc are currently producing and extracting approximately

22% of this 30%. However, only 10 percent of the Athabasca oil reserves can be extracted

economically using the surface mining methods. The demand for innovative new technology for

the extraction of oil sands is high (3).

2.1 GENERAL OVERVIEW OF SAGD

In the last two decades Steam assisted gravity drainage (SAGD) combined with horizontal well

technology is one of the most famous concepts developed in Reservoir engineering. The concept

of gravity drainage is not new. However, its use to unlock heavy oil and bitumen reserves to

profitable recovery was not so obvious. The concept of SAGD was first studied and suggested by

Roger Butler. He developed the gravity drainage theory which predicts the rate at which the

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SAGD process will take place and through experiments also confirmed the viability of the

concept. (4)

SAGD is a conduction/convection heat transfer ablation process in which the steam from the

injection well transfers its heat to the high viscous cold bitumen and reduces its viscosity by

increasing temperature and makes it mobile and under the influence of gravity it falls to the

production well and exposes the new element of bitumen to be produced in the similar way (4)

.

The SAGD process is able to economically recover 55 percent of the original bitumen in place.

There are many engineering considerations for SAGD process that includes (3)

.

Recovery Rate.

Thermal efficiency.

The capability and economics of drilling horizontal well pairs.

Steam quality.

Steam injection Rate.

Steam Pressure.

Minimizing Sand Production.

Reservoir Pressure maintenance.

Figure 2.1 SCHEMATIC OF SAGD WITH TWO HORIZIONTAL WELLS

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2.2 START UP

Fluid communication between the injector and the producer plays a vital role in performing the

SAGD with parallel wells. Initially bitumen saturation and the viscosity are so high that the

communication must be artificially developed before SAGD can proceed. During the start up

phase the steam is initially circulated in the injector and the producer until hot communications

are established. Two string of tubing in both the wells, one in the injector and the other one in the

producer are required to carry out this process efficiently (6)

. If the production casing is not

spacious enough to accommodate two tubing strings, the alternative method would be to inject

and produce through the annular space; however it is not advisable because it can results in

various operational problems. When the steam reaches its breakthrough the circulation is stopped

and the steam is only injected at the upper well at the constant pressure below the fracture

pressure. Start up process is slow and the achieved oil production rates in this phase are also low,

it is believed that the injection of the steam with the Naphtha will result in the faster process (10).

Figure 2.2 HOT FINGERING IN SAGD

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2.3 BREAK THROUGH TIME

The break through time should be calculated using the Following Formula (6)

;

Tbt= (1.976 – 0.74C+ 0.174C2- 0.014C

3) S

2 ln(S/W)

Where

C= Ka∆ф ln (S/W)

And

Tbt= Break through Time, Days.

S= is the distance between the injector and the producer.

W= Wellbore outside diameter, meter

Ka= absolute permeability between the wells, Darcy

∆ф= Liquid Potential difference between the injector

And the Producer, MPa

2.4 GROWING PHASE

It is the beginning of the SAGD Process, steam has elevated to the top of the formation and it

results in the high production rates. During this phase it is mandatory to control the temperatures

of the fluids produced in order to stop the steam flowing with them. This mechanism is called

Steam Trap (10)

. It helps to maintain the temperature at the well head so that it always remains

below the steam saturation temperature. If the temperature is maintained properly most of the

steam remains in the chamber and increase the efficiency of SAGD (4)

.

2.5 EFFECT OF STEAM CHAMBER PRESSURE:

The Steam that exists in the steam chamber is in saturated conditions. Higher pressure of the

steam results in lowering the viscosity and increasing the temperature. This leads to a higher oil

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flow rate value. At the same time higher steam pressure also results in lower thermal efficiency

and higher Steam-Oil Ratio (7)

.

Sensitivity studies are performed in order to determine the optimum steam pressure which is

result in best economical output. Steam chamber pressure plays a vital role in determining the

kind of the production system we need to choose. Higher pressure would eliminate the option of

using the artificial lift for the recovery as the natural lift will be enough to produce the fluids.

When pressure is low, artificial lift becomes necessary (7)

.

2.6 SPACING BETWEEN WELLS PAIR

One of the most important parameter in designing the SAGD operation is to select the adequate

spacing between the well pairs. The spacing between wells is a very important parameter as

create hot communications between the injector and the producer depends upon it. Small amount

of variation is acceptable which usually occur during drilling operation (4)

.

2.7 LENGTH OF HORIZONTAL WELLS

Length of the horizontal wells is also a very important factor that needs to be considered in

designing the SAGD operation. Reservoir quality and its hydraulic capacity play a very vital role

in determining the maximum length of well pair that can be used. The length of the well should

not be too long as it can make the controlling of the well difficult. The economical factor also

has to be considered before choosing the length of the pair. Results from many different pilots

suggest that too much long well pair does not operate on steam trap control (4).

2.8 WELL CONFIGURATION

There are three major horizontal well arrangements for SAGD.

The First one involves two wells one drilled above the other. The Producer is located at

the base of the formation while the injector is placed several meters above and it is

parallel to the producer (5)

.

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The second one involves the dual tubing strings with the single well. Steam is injected

through one of tubes from the surface and exits at the toe of the well. Fluid mobilizes

and condenses through the horizontal part of the well, drains and it is collected through

the production tubing from the heel of the surface (5)

.

The third one uses the combinations of horizontal and vertical wells. The vertical well is

drilled at the toe end of the horizontal well, or the combinations of several vertical wells

are drilled up at the top of a formation with the horizontal producer located at the base

(5).

Any of the above schemes can be used; however the performance of the process is determined

by the geometric interaction between the steam chamber and the horizontal producer (5)

.

2.9 WELL PLACEMENT

One of the major factors that results in the effective SAGD process is the proper location of the

horizontal well in the geological formation. The distance between the wells plays a vital role in

performing a good SAGD operation. Close spacing can result in rapid heat communication

problem, while big separation between the wells will result in long delays in obtaining a

significant production (5)

.

The use of the Measurement While Drilling (MWD) and Magnetic Guidance Tool (MGT)

allows close tolerance drilling. Vertical errors of less than 1m for separation distances of - 10m

and <2m lateral displacements over 1000m well lengths are achievable. Appropriate separation

may not be obtained in the build section and wells may be drilled too close or even into one

another. The experience and training of the field technicians become critical (4)

.

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Figure 2.3 Horizontal wells Configuration

2.10 PROCESS CHARACTERISTICS

Steam Chamber pressure remains constant. Gas along with water and steam are condensed in the

solution. Thermal expansion helps to avoid instabilities such as coning and channeling. Steam

injection rate does not seriously affect the oil production. Maximum oil production occurs when

the steam is at the top of the chamber. SAGD does not give acceptable results when the vertical

production wells are used because the flowing conditions are low (10)

.

2.11 ADVANTAGES

Steam assisted gravity drainage has certain advantages as compared to the conventional thermal

recovery techniques. It has the series of the technical, financial and environmental advantages

over other process that have made it more attractive for the Heavy oil industry (10)

.

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2.11.1 TECHNICAL

It utilizes low injection pressure a crude oil mobility is greater. Less pressure drop per unit length

helps to prevent water coning. So, results in less Sand Production (10)

.

2.11.2 FINANCIAL

Operation cost is less as compared to the other process that makes it more profitable. The cost for

drilling the 1000-1500 m wells is high as compared to the vertical wells but the production

achieved will be 10 times greater. Wells drilling from the same pad greatly reduce cost. In most

of the SAGD processes, artificial lifting is not required to lift the fluid to the surface depending

on the depth and pressure of the oil field. With minimum sand production, works over operations

are not needed in most of the cases (10)

.

2.11.3 ENVIRONMENTAL

In SAGD horizontal wells replaces the production from the vertical wells, these horizontal wells

can be drilled from the same pad which results in

Low ground disturbance.

Generating low environmental impact.

Minimizing the need for Facilities.

2.12 LIMITATIONS

Handling of high steam quantities in the form thin and low quality oil fields is not possible.

SAGD is a steam injecting process so sometimes the efforts are limited by oil well depths,

because of the steam critical pressure (10)

.

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CHAPTER 3

EFFICIENCY OF SAGD

Economically and environmentally SAGD is a major advance thermal process of all time. It uses

only 70% of steam for the same oil recovery than we do with other thermal processes. It recovers

more oil in place and its surface impact is modest. Usually the whole facility of SAGD includes

injector and producer requires area of about 1 hectare including well site. The average

production rate of SAGD wells is about 500BOPD with the exception of 2000BOPD at some

extent making SAGD models the best productive technique in North America.

Figure 3.1 SCHEMATIC VIEW OF THE FIELD

SAGD with all types make the Oil and Gas industry capable for the development of the largest

hydrocarbon reserve on the earth. However due to reservoir’s complications, heterogeneities and

other variations, application of SAGD sometimes is not an easy task. Specialist and researchers

are very keen to find out the best economic and effective way to produce the biggest reserves

worldwide.

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3.1EXPANSION OF HORIZONTAL SWEEP VOLUME AND REDUCTION

OF STEAM OVERRIDE

The expanding dynamic of the steam growth in SAGD shows that steam override vertically with

high velocity and forms a cylindrical shape. Addition of Nitrogen (N2) in SAGD makes the

steam growth like an oval. It doesn’t only restrain the steam to go into the thief zone but also it

makes an insulating heat layer which reduces heat loss. It has been noticed from the oil

production in different pilots that oil steam ration economic efficiency is increased by reducing

the amount steam injection. The optimum range of Nitrogen (N2) is almost the 20% of steam

injection.

3.2 INCREASING MOBILITY

Nitrogen has its nature to make crude oil less viscous, so when its being injected into the crude

oil it reduces the viscosity thus increasing mobility. The mobility of the crude oil depends upon

the solubility of the Nitrogen. The higher the solubility of the Nitrogen into crude oil the higher

the mobility is. To increase the solubility of N2 , temperature and pressure are increased because

N2 dissolved in crude alters the intermolecular forces between liquid liquid into intermolecular

forces between liquid and gas.. Tests have shown that at 100 0C and 2MPa the crude viscosity is

1,444 mPa.s and at 250 0C and 4 MPa is 8.1 mPa.s.

3.3 CONTROL OF STEAM INJECTION RATE

The results have shown that decreasing the steam injection could increase the oil steam ratio to

improve economic efficiency. Therefore, simulation steam injection was carried out. Heat loss

calculation determined that injection rate for a single well is 100 t/d to ensure that steam behaves

70% same at the bottom of the well. Development proven that 80% of the steam is actually

required for injection. Simulation results show that original steam value ( 875t/d) has oil

production 76.3(104 t) while at 80% of the original steam value (700t/d)has oil production

81.7(104 t).

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CHAPTER 4

MODELING OF A SAGD RESERVOIR

We have built, and run the model on CMG, Computer Modeling Group using STARS as a

reservoir simulator.

4.1 COMPUTER MODELLING GROUP

Computer Modelling Group is a software company that makes Reservoir Simulators for the

petroleum industry. It is one of the largest providers of reservoir simulators throughout the

world. CMG technologies are used worldwide. Initially the company was known to be experts in

dealing with Heavy oil, with the span of time they expanded their technology and now they are

considered to be experts into all aspects of reservoir flow modelling. Over the past 32 years, the

main goal is to introduce new reservoir simulations techniques that can access in determining

reservoir capacities and maximize potential recovery. The Company’s head quarter is based in

Calgary, Alberta. Some head Offices are based in London, Houston, Dubai and Caracas. CMG

offers three different types of simulators (9)

.

IMEX

GEM

STARS

4.2 IMEX (Implicit Explicit Black Oil Simulator)

It is the CMG’s full featured Black Oil Simulator. It can used to model the three phase fluids in

gas, gas-water and oil-water reservoirs. It can also model the primary, secondary and pseudo-

miscible and polymer injection processes (9)

. It can also deals with

Studies related Coning.

Performance of the reservoir under surface constraints.

Gas injection

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Water flooding

Gas deliverability and its forecasting.

4.3 GEM (Generalized Equation of State Model Compositional Reservoir

Simulator)

It is the CMG’s compositional simulator that is used to model that can model three phase,

multiphase fluid compositions. It also provides well management options, surface separator

facilities, gas plant separation stages and can also help to model the flow from sand face to the

outlet (9)

. It can effectively model:

Recovery of Gas Condensate.

Volatile oil reservoirs.

Carbon dioxide and hydrocarbon injection

Cycling and re-cycling of Gas

WAG processes

4.4 STARS

STARS, Steam, Thermal and Advanced processes Reservoir Simulator is the industry’s leading

simulator. STARS is a new generation simulator which can simulate chemical flooding, thermal

processes, steam injection, dual porosity/ permeability, flexible grids etc. It was built to deal with

steam flooding, dry and wet combustion inside the earth, steam cycling and many other types of

chemical additives. Its robust reaction kinetics and geomechanics capabilities make it the most

complete and flexible reservoir simulator available for modeling the complex oil and gas

recovery being studied and implemented today(9)

.

STARS require some good understanding of reservoir engineering and reservoir simulation pre-

requisites. Our model is based on STARTS and here we will cover all the necessary details and

will provide step by step procedure followed the making of that model.

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4.5 DESCRIPTION OF THE RESERVOIR

The reservoir model used in my study is fabricated. All the parameters used are either assumed

or they are taken after going through different SPE papers and also the templates files that are

available in CMG software. Some of the parameters related to the geometry of the reservoir are

taken by the instruction given by my supervisor.

Before selecting the mesh size, different cases were considered and the simulation is run. In one

of the case the grid block dimensions for the cap rock and the under burden were taken as 12x

12x12 in x, y and z direction, The dimension of the reservoir rock were taken as 14x14x14.

However when the simulation is run if was found out that it does not have any effect on the

cumulative production. The dimension in the model are taken as advised by my supervisor

The reservoir is characterized into three different layers, cap rock, reservoir Rock and under

burden. The grid block dimensions for the Cap rock and under burden are 12x16x16 in x, y and z

directions. The dimensions for the reservoir rock are 16x16x16 in x, y and z direction. The true

vertical depth for the area of interest is 162 m where 100m is occupied by the cap rock , 32m by

reservoir rock and 30 m by the Under burden. The total length of the area of interest is 4600m,

where 3000m is occupied by cap rock and under burden while the 1600m is occupied by the

reservoir rock. The width of the reservoir is 1008 m. The distances between both the horizontal

wells are 5 m. The model is shown graphically in the figure below.

Figure 4.1 RESERVOIR MODEL

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4.6 SAGD RESERVOIR MODEL ON STARS

Open CMG software

Create a new model on CMG using BUILDER.

Select STARS as simulator, SI as Working units, Single Porosity and 01-01-2002 as

simulator start date.

4.7 MAKE OF A MODEL

To make a final and simple model in CMG Builder, we will fill the parameters reservoir,

components, rock fluid, initial condition, numerical and well & Recurrent respectively.

4.7.1 RESERVOIR:

Select reservoir

Create grid

Cartesian geometry.

25

We have selected a model of 4600m in length, 1008m width and 162m height.

So in Number of Grid Blocks, put 12, 63 and 3 in I, J and K direction respectively.

I direction in Block widths, put 4*375, 4*400, 4*375, to make 4600m in length, in which

right/left side of the reservoir is 1500m and 1600m is of the reservoir.

J direction in Block widths, put 63*16 to make it 1008, also to make 63 blocks of 16m.

26

4.7.2 THERMAL PROPERTIES:

In our model we have used three different rock layers; in this section we assign the different

values to the Rock compressibility, Dilation Recompaction, Rock compaction properties and

over burden heat loss (8)

. The Properties assigned to Rock Layer one is shown below:

Volumetric heat capacity as 2.35 e6.

In thermal conductivity phase mixing, Reservoir rock as 1.25 e5, Oil, water and Gas

phase as 1.49 e5.

27

4.7.3 OVERBURDEN HEAT LOSS:

For the overburden heat loss section put:

Volumetric Heat Capacity: Overburden/Under burden as 1.169 e6.

Thermal Conductivity: overburden/Under burden as 7.49 e4.

28

4.7.4 ROCK COMPRESSIBILITY:

In the rock compressibility section put:

Porosity reference pressure as 2654.

Formation compressibility as 9.6 e-6

.

4.7.5 IMPORTANT PARAMETERS:

Property Symbol Value Unit

Pressure P 2654 KPa

Temperature (steam) T 295 0C

Permeability (I,J,K)(Layer 1 & 3) K 0 Md

Porosity(Layer 1 & 3) Φ 0 -

Grid Thickness (layer 1) h1 100 M


29


Thermal No (layers 1) Th1 1 -



TABLE 1 IMPORTANT RESERVOIR PARAMETERS FOR MODELLING.

4.7.6 COMPONENTS:

Heavy crude oil or extra heavy crude oil is any type of crude oil which does not flow easily. It is

referred to as "heavy" because its density or specific gravity is higher than that of light crude oil.

Heavy crude oil has been defined as any liquid petroleum with API gravity less than 20° (4)

.

Physical properties that differ between heavy crudes lighter grades include higher viscosity and

specific gravity, as well as heavier molecular composition.

In this section we assign the values of the heavy oil, water and gas phases. We import the fluid

properties and put the following values initially. The total number of components are 3, water,

gas and oil. The total number of components in the oil gas and water phase is 3 while the total

number of component in liquid phase is 2. The Table below shows the values of the properties

that are used in order to create our model.

Property Water Oil Gas

Units

Cmm 0 0.508 0.01604

Kg/gmole

Molden 0 1960.6 42411

Gmole/m3

Cp 0 5.63E-07 9.48E-05

1/KPa

ct1 0 8.48E-04 2.30E-02

1/deg C

Pcrit 0 1360 4640

Kpa

30

Tcrit 0 624065 -82.49

Deg C

cpl1 0 1130 12.83

J/gmole.C

cpg1 0 841 35.2

J/gmole. C

Hvapr 0 1346 1770

J/gmol

Avg 0 0 2.80E-04

Cp

Bvg 0 0 0.667

Cp

Avisc 0 1.74E-06 1.90E-04

Cp

Bvisc 0 6232.74 3432.41

Cp

kv1 0 0 4.39E+04

------

kv1 0 0 0

-----

kv3 0 0 1.97E+00

-----

kv4 0 0 -1.96E+03

-----

kv5 0 0 -2.73E+02

-----

TABLE 2 RESERVOIR PROPERTIES

31

4.7.7 REFERENCE CONDITIONS:

Reference Pressure 101.3 Kpa

Reference Temperature 21 C C

Surface Temperature 101.3 C

Surface Pressure 15.6 Kpa

TABLE 3 REFERENCE CONDITION

After inputting the components properties, following results were obtained.

4.7.8 PRESSURE V/S WATER FORMATION VOLUME FACTOR

Figure 4.2 PLOT BETWEEN BW AND PRESSURE

32

Water formation volume factor (Bw) is defined as the ratio between the volume of water at

reservoir conditions with the stock tank conditions. Bw is used to convert the flow rate of

water to reservoir conditions.(4)

It can be measured in the laboratory or using different correlations. Under most conditions it has

a value of approximately 1.0. From the graph it can be concluded that as we are increasing the

pressure the value of water formation volume factor decreases.

4.7.9 PRESSURE VS WATER DENSITY

Figure 4.3 PLOT BETWEEN WATER DENSITY AND PRESSURE

The above plot shows the relation between the density and the Pressure, It can be concluded that

as we are increasing the pressure the density of water tends to increase keeping at the reference

temperature of 21 C

33

4.7.10 ROCK PROPERTIES:

Click Rock Fluid.

Open Create or Edit Rock Type.

Then click on Relative Permeability Tables

Put values of Sw, Krw and Krow ( you can also export the values using DAT. File)

34

4.7.11 VALUES

Sw Krw Krow

0.15 0 1

0.2 2.00E-04 0.95

0.25 1.63E-03 0.84

0.3 5.50E-03 0.72

0.35 1.30E-02 0.6

0.4 2.54E-02 0.47

0.45 4.40E-02 0.35

0.5 6.98E-02 0.24

0.55 1.04E-01 0.165

0.6 1.48E-01 9.30E-02

0.65 2.04E-01 7.00E-02

0.7 2.71E-01 4.00E-02

0.75 3.52E-01 1.50E-02

0.8 4.47E-01 0.00E+00

0.85 5.59E-01 0.00E+00


SI Krg Krog

0.15 1 0

0.2 0.95 2.00E-04

0.25 0.84 1.63E-03

0.3 0.72 5.50E-03

0.35 0.6 1.30E-02

35

0.4 0.47 2.54E-02

0.45 0.35 4.40E-02

0.5 0.24 6.98E-02

0.55 0.165 1.04E-01

0.6 9.30E-02 1.48E-01

0.65 7.50E-02 2.04E-01

0.7 4.50E-02 2.71E-01

0.75 2.70E-02 3.52E-01

0.8 2.00E-02 4.47E-01

0.85 1.00E-02 5.59E-01

0.9 5.00E-03 6.87E-01

0.95 0.00E+00 8.34E-01

1 0.00E+00 1.00E+00


36

4.7.12 RELATIVE PERMEABILITY CURVES

Figure 4.4 RELATIVE PERMEABILITY CURVE 1

Figure 4.5 RELATIVE PERMEABILITY CURVE 2

37

4.7.12 Relative permeability:

Stone's modified model is based on two-phase relative permeability functions .In this model the

gas and the water relative permeability functions are given as

Krw = Kr,w (Sw) and Krg = Kr,g (Sg)

The oil relative permeability function is estimated on basis of the relative permeability in an Oil

Water system:

Krow = Kr,ow (So)

and the relative permeability in an Oil Gas system:

Krog = Kr,og (SL) ; Where SL = 1 – So

Figure 4.6 STONE RELATIVE PERMEABILITY MODEL

38

4.7.13 NUMERICAL

It defines those parameters that control the simulator's numerical activities such as time stepping,

Iterative solution of non-linear flow equations and the solution of resulting system of linear

equations. In our reservoir model we did not play a lot with the numerical section as most of

values are taken as default values saved in the CMG star simulator (8)

. Below are some of the

snap shots of the values that are used in the numerical section.

Click on Numerical Tab

Click on Time Step Control and start putting the values

After putting the values Press OK.

41

4.7.14 WELLS & RECURRENT

In this model we have two horizontal wells, one producer and one injector. Both horizontal wells

are 16m apart.

Single click the WELLS & RECURRENT.

Double click the wells.

Select injector.

4.7.15 INJECTOR WELL

4.7.16 CONSTRAINT

PUT:

MAX BHP bottom hole pressure as 5500

MAX STW surface water rate as 150

42

4.7.17 INJECTION FLUID:

PUT:

Water as 1.

Gas and Oil as 0.

4.7.18 PERFORATIONS:

Open the wells tree and select Injector.

Select perforations.

43

Put 16 in Length, 100 in Block Top and 116 in Block Bottom.

4.7.19 PRODUCER WELL

4.7.20 CONSTRAINT:

PUT:

MIN BHP bottom hole pressure as 500.

MAX STL surface liquid rate as 150.

44

Open the produce tree.

Select perforations.

Put 16 in Length, 116 in Block Top and 132 in Block Bottom.

45

CHAPTER 5

EFFECT OF INJECTION PARAMETERS ON SAGD

The injection parameters can have a big effect on the ultimate recovery from the reservoir. Two

cases are considered in order to analyse their effects.

BASE CASE

Alternate Case

5.1 BASE CASE

In this case the steam temperature was considered as 295 C, bottom hole pressure is 5550 KPa,

Flow rate is 150 m3/day. Using these values the simulation was run and the following graph is

obtained.

Figure 5.1 PLOT BETWEEN CUMMULATIVE OIL AND TIME (BASE CASE)

This is graph between the cumulative oil production with time. From the graph it can be

concluded that the production was low in the initial part of the SAGD operation but with time it

increases and reaches the value of about 3000m3/day in 2007.

0

500

1000

1500

2000

2500

0 500 1000 1500 2000 2500 3000 3500 4000

Cu

mm

ula

tive

Pro

du

ctio

n (

m3

/day

)

Time (Days)

BASE CASE

Base Case

46

5.2 ALTERNATE CASE 1

In order to perform this task following steps were taken.

Open CMG

Open the model made in the base case

Go to wells section and click it.

Click on injector well

Go to Steam Temperature and change it to 200 C and press OK.

Run the simulation again and using the irf. File , see the results


0

500

1000

1500

2000

2500

3000

3500

0 1000 2000 3000 4000

Cu

mm

ula

tive

Pro

du

ctio

n (

m3

/day

)

Time (Days)

Steam Temperature 295

Steam Temperature 200

47

From the graph it can be concluded that as decrease the Steam Temperature, the cumulative

production of the oil decreases.



Open CMG




Go to constrain and change BHP from 5550 KPA to 7000 KPA and press OK.

Run the simulation again and using the irf. File , see the results.

48


From the graph it can be concluded that as we increase the BHP, the cumulative production of

the oil decreases.



Open CMG




Go to constrain and change flow rate from 150m3/day to 100 m

3/day and press OK.

0

1000

2000

3000

4000

5000

6000

0 1000 2000 3000 4000 5000

Cu

mm

ula

tive

Pro

du

ctio

n (

m3

/day

)

Time (Days)

BHP 5500

BHP 7000

49

Run the simulation again and using the irf. File, see the results


From the graph it can be concluded that as we decrease the flow rate, the cumulative production

of the oil increases.

0

1000

2000

3000

4000

5000

6000

0 1000 2000 3000 4000 5000

Cu

mm

ula

tive

Pro

du

ctio

n (

m3

/day

)

Time (Days)

Effect of Flow Rate

Flow rate - 150

Flow Rate 125

50



Open CMG




Go to perforations and change the block address from 7,1,2/1,1,1 to 5,1,2/ 1,1, and press

OK.

Run the simulation again and using the irf. File, see the results


0

500

1000

1500

2000

2500

3000

3500

0 1000 2000 3000 4000 Cu

mm

ula

tive

oil

Pro

du

ctio

n

(m3

/day

)

Time(Days)

Base Case

Different well location

51

From the graph it can be concluded that as we change the location of the well, the cumulative

production of the oil decreases.



Open CMG



Click on Production well

Go to constrain and change BHP from 500 KPA to 250 KPA and flow rate from 150 m3/day to

250 m3/day and press OK.

Run the simulation again and using the irf. File , see the results

52


From the graph it can be concluded that as we decrease the BHP and increase the flow rate in the

production well, the cumulative production of the oil increases

5.7 Cumulative Effect

0

2000

4000

6000

8000

10000

12000

14000

0 1000 2000 3000 4000 5000

Cu

mm

ula

tive

Oil

pro

du

ctio

n (

m3

/day

)

Time (Days)

Series1

Series2

0

2000

4000

6000

8000

10000

12000

14000

0 1000 2000 3000 4000

Cu

mm

ula

tive

Oil

Pro

du

ctio

n (

m3

/day

)

Time (Days)

Production Constrains

Base Case

Steam Temp 200

Bottom Hole Pressure 7000

Flow Rate

Location of Well

53

CHAPTER 6

DISCUSSION AND CONCLUSION:

DISCUSSION

Economically and environmentally SAGD is a major advance thermal process of all time. It

consumes 70% of the steam usually required in other thermal processes. The efficiency of the

SAGD models can be increased by the following alterations:

Additions of N2 in SAGD make crude less viscous by breaking the liquid/liquid intermolecular

forces into liquid/gas intermolecular forces. Moreover, addition of N2 not only restrains the

steam to get loss into thief zone but also makes an insulating layer which reduces heat loss.

Solubility of N2 into crude oil makes crude less mobile to flow. The mobility of crude oil directly

depends upon the solubility of the N2 in it. The higher the solubility of N2 is, the higher the

mobility will be.

The results have also shown that by decreasing the steam injection, oil steam ration can be

increased to improve economic efficiency.

CONCLUSION

The steam-assisted gravity drainage (SAGD) process is currently the widely used one among the

in-situ recovery methods to produce bitumen from Alberta oil sands in Western Canada. A

thermal process requires very small grid size to provide the better description in the reservoir

simulation model than the coarse grid; however the simulation runtime will take longer. The

relationship between the number of grids and runtime is not linear but exponential. It is

important to design the proper grid size giving reasonable results with shorter runtime.

In this project, we discussed different parameters which cause variation of heavy oil production,

SAGD modelling, well spacing between two wells in SAGD, and results after playing with

different parameters will also be discussed.

For the Conventional SAGD case, oil production rate increased with increasing vertical spacing

54

between the wells; however, the lead time for the gravity drainage to initiate oil production

became longer. Efficiency of SAGD is also discussed thoroughly. From our analysis we can

conclude the following results.

Additions of N2 in SAGD make crude less viscous by breaking the liquid/liquid

intermolecular forces into liquid/gas intermolecular forces.

The well location can have an impact in the overall oil Production.

If the steam temperature is reduced, it will have an adverse affect on the Cumulative oil

production.

The mobility of crude oil depends upon the solubility of N2 in it.

Solvent can reduce the viscosity of bitumen and makes it lighter.

Selection of the solvent is very important as it can have a huge impact on the overall cost

of the project

Porosity of the formation can have an affect on the SAGD operation. Higher porosity

values will result in less Water oil ratio. Less WOR is good from economical point of

view.

55

REFERENCES

1. L.A. Bellows, V.E Bohme, Athabasca Oil Sands, Oil and Gas Conservation board of

Alberta. ATLA.

2. L.Chow*, R.M. Butler, Numerical simulation of the Steam Assisted Gravity Drainage

process, University of Calgary, Volume 35, No 6, June 1996.

3. C.V. Deutsch, J.A.McLennan, Guide to SAGD Reservoir Characterization Using

Geostatistics, Centre for Computational Geostatistics, Guide book series Vol 3.

4. Dr. Redford, lecturer of In-situ recovery of Oil sand, University of Alberta, Lectures

papers.

5. Ben Nzekwu, Drilling and Completion for Steam Assisted Gravity Drainage Operations

JCPT, The Journal for Canadian Petroleum Technology.

6. N.R Edmunds and S.D. Gittins, Article- Effective application of Steam Assisted Gravity

Drainage of Bitumen to long horizontal well pairs, JCPT, 93-06-05

7. M. Pooladi-Darvish, L. Mattar. SAGD Operation in the Presence of Overlying Gas Cap

and Water layers --- Effect of Shale Layers, JCPT, Paper 2001-178, Vol 41, No 6, June

2002.

8. Computer Modeling Group Limited, User Guide STARS, Advanced process and Thermal

Reservoir Simulator, Version 2009,

9. Computer Modeling Group Limited, Calgary. Retrieved from http://cmgl.ca/

10. Edwin Rodriguez, Jamie Orjuela, Feasibility to apply the SAGD in the country’s Heavy

Oil Field, Science Technology and future Colombian Petroleum Institute, 2004.

ghayas final project report

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