UPTEC ES07 018
Examensarbete 20 p
Oktober 2007
Russian Oil
a Depletion Rate Model estimate of the future
Russian oil production and export
Aram MĂ€kivierikko
UPTEC ES07 018
Examensarbete 20 p
Oktober 2007
Russian Oil
a Depletion Rate Model estimate of the future
Russian oil production and export
Aram MĂ€kivierikko
Teknisk- naturvetenskaplig fakultet
UTH-enheten
Besöksadress:
Ă
ngströmlaboratoriet
LÀgerhyddsvÀgen 1
Hus 4, Plan 0
Postadress:
Box 536
751 21 Uppsala
Telefon:
018 â 471 30 03
Telefax:
018 â 471 30 00
Hemsida:
http://www.teknat.uu.se/student
Abstract
Russian Oil
Aram MĂ€kivierikko
Oil is a heavily used natural resource with a limited
supply. Russia is one of the largest oil producers and
the second largest oil exporting country in the world.
Many surrounding countries are dependent on Russian
energy. Swedish oil import from Russia has grown
from 5% to 35% during 2001-2005.
The fall of the Soviet Union in 1991 caused the
Russian oil production to drop by 50%. The production
is currently growing again â but how will it develop in
the future?
This report studies different scenarios for Russian oil
production and export based on three different
estimates of how much oil Russia has left today (70,
120 or 170 Gb), combined with estimates about how
fast Russia can produce the oil (a depletion rate of 3%,
4.5% or 6%).
In the worst case, Russian oil production and also the
oil export will peak very soon or has already done so
in 2006. In the best case, a constant export can be
held until 2036. It is not likely that the Russian
production will increase more than 5-10% over todayâs
level.
ISSN: 1650-8300, UPTEC ES07 018
Examinator: Ulla Tengblad
Ămnesgranskare: Allan Hallgren
Handledare: Kjell Aleklett
3 (100)
Sammanfattning
Bakgrund
Olja Àr en kraftigt utnyttjad men begrÀnsad naturresurs. Fossila brÀnslen som kol och olja
spelade en avgörande roll för den industriella revolutionen. I jÀmförelse med andra brÀnslen
har olja en hög energidensitet och Àr lÀtt att transportera, lagra och anvÀnda.
à r 2006 anvÀndes ungefÀr 84 Mb/d
1
oljeprodukter i vÀrlden. à r 2030 förutspÄs anvÀndningen
ha ökat till 116 Mb/d (+40%). Samtidigt hittas en allt mindre mÀngd olja. Sedan mitten av
1980-talet har oljeproduktionen med nÄgra undantag varit större Àn mÀngden hittad olja.
Eftersom en stor del av vÀrlden redan undersökts, Àr chansen att hitta nya stora oljefÀlt liten.
Detta kommer sÄ smÄningom att leda till att oljeproduktionen nÄr en topp och dÀrefter
kommer att minska. I kombination med den ökade efterfrÄgan kan detta leda till stora
samhÀllsproblem om ÄtgÀrder ej vidtas i tid.
Rysslands roll
Ryssland Àr en av vÀrldens största oljeproducenter och vÀrldens nÀst största oljeexportör.
MÄnga omkringliggande lÀnder Àr beroende av rysk energi. Den svenska oljeimporten frÄn
Ryssland har vÀxt frÄn 5 % till 35 % under perioden 2001-2005.
Ryssland hade i princip en dubbel produktionstopp pÄ ca 11 Mb/d i början och slutet av 1980-
talet. Sovjetunionens fall 1991 ledde till att den ryska oljeproduktionen föll med 50 %. Sedan
Är 2000 har produktionen ÄterhÀmtat sig. I dagslÀget Àr produktionen 9,5 Mb/d och ökar
fortfarande, men hur lÀnge kan ökningen hÄlla i sig? Kan Ryssland bidra till att tillgodose det
förutspÄdda ökade oljebehovet i vÀrlden genom en konstant eller ökande export?
Modellering av Rysslands oljeproduktion och -export
Tre olika produktionsscenarier studeras:
1. Konstant produktion
2. Konstant export (nÄgot ökande produktion p.g.a. ökande inhemsk oljeanvÀndning)
3. Exportökning. Exporten ökas med 2 Mb/d pÄ 8 Är, dÀrefter konstant export.
Tre bedömningar av hur mycket olja Ryssland har kvar (70, 120 eller 170 miljarder fat) Är
2006 har gjorts genom att dela in ett större urval av bedömningar i tre grupper baserat pÄ
storlek och sedan ta ett medelvÀrde för varje grupp.
För att kunna bedöma oljeexporten behövs utöver oljeproduktion en uppskattning pÄ storleken
hos den inhemska oljeanvÀndningen.
En modell har skapats baserad pÄ maximal utarmningstakt (depletion rate). Utarmningstakt Àr
en slags mÄtt pÄ hur snabbt oljan kan produceras:
!
utarmningstakt
=
Ă„rlig oljeproduktion
mÀngd olja kvar i början av Äret
Eftersom en mindre mÀngd olja finns kvar efter varje Är, ökar utarmningstakten med tiden vid
konstant eller ökande produktion. Grundtanken med modellen Àr att lÄta produktionen styras
av valt scenario tills en bestÀmd maximal utarmningstakt uppnÄtts. DÀrefter minskas
1
Mb/d = miljoner fat per dag; 1 fat = 159 liter
Aram MĂ€kivierikko
4 (100)
produktionen exponentiellt sÄ att den maximala utarmningstakten inte överskrids, se exempel
i Figur 1. Tre olika maximala utarmningstakter har anvÀnts: 3 %, 4,5 % och 6 %.
Figur 1. Principen för utarmningstaktsmodellen. I exemplet antas Ryssland ha 120
miljarder fat olja kvar och en maximal utarmningstakt pÄ 4,5 %.
Resultat
De mest intressanta resultaten Ă€r Ă„ret nĂ€r produktionen nĂ„r sin topp samt âexport-stopp-Ă„retâ
dÄ Rysslands inhemska konsumtion överstiger produktionen (Figur 2). I vÀrsta fall kommer
produktionen att nÄ en topp inom de nÀrmsta Ären. I bÀsta fall nÄs toppen först 2036. Det mest
troliga Àr en topp omkring 2015-2020. Det Àr inte troligt att den ryska produktionen kommer
att öka enligt scenario 3 (Exportökning) â den högre produktionsnivĂ„n skulle kunna hĂ„llas
under en sÄ kort tid att det inte skulle bli ekonomiskt försvarbart att bygga den nödvÀndiga
infrastrukturen.
Tanken med modelleringen har varit att ta fram ett sÄ pass brett spann av oljeproduktions- och
-exportmöjligheter att man med stor sÀkerhet kan sÀga att den verkliga produktionen/exporten
kommer att hamna nÄgonstans dÀremellan. Bara framtiden kan utvisa om sÄ blir fallet!
Figur 2. Min-, medel- och maxvÀrden pÄ tidpunkt för produktionstopp (P) och export-
stopp (E) uppdelat pÄ mÀngd kvarvarande olja. De fÀrgade markeringarna visar
resultaten frÄn en enklare s.k. Hubbert-kurva som anvÀnts för jÀmförelsesyfte.
5 (100)
Reading instructions
The thesis is divided into an introductory part about oil, three main parts and an appendix.
Some of the included chapters contain background information for the interested reader. The
most important chapters are marked with
bold
.
About oil
Readers with previous knowledge of oil can skip the âAbout oilâ part or use it as a reference.
Chapter 1 describes oil related terms used in this thesis.
Chapter 2 discusses the importance of oil.
Part one: Introduction
Chapter 3 describes the peak oil concept
Chapter 4
describes the importance of Russia as an export country.
Chapter 5 discusses Russian importance for Sweden.
Part two: Russia
Readers with previous knowledge of the Russian oil market are recommended to read at least
the bold-marked chapters. Others might find it useful to read all chapters.
Chapter 6 is a review of the oil production history of Russia.
Chapter 7 describes the oil producing regions in Russia
Chapter 8
gives an overview of the Russian oil companies. At least chapter
8.4
discussing the
future plans of Russia should be read in order to understand later discussion.
Chapter 9
discusses different estimates about how much oil is left in Russia. This is crucial
for the modelling approach used.
Part three: Modelling
This is the most important part of the thesis and should be read in its entirety.
Chapter 10
introduces the three studied scenarios. Important concepts are also described.
Chapter 11
models Russian oil production using the Hubbert curve.
Chapter 12
describes the Depletion Rate Model.
Chapter 13
describes the results from the Depletion Rate Model.
Chapter 14
discusses the results obtained from the model.
Appendices and references
Appendix A (chapter 15) gives a closer look on the Swedish domestic energy usage.
Appendix B (chapter 16) describes the assumptions made for the Hubbert curve.
Appendix C (chapter 17) gives a better insight in the inner workings of the Depletion Rate
Model.
Aram MĂ€kivierikko
6 (100)
Contents
ABOUT OIL .....................................................................................................9
1
UNITS AND TERMINOLOGY ........................................................................................................................10
1.1
U
NITS AND PREFIXES
......................................................................................................................................10
1.2
T
ERMINOLOGY
................................................................................................................................................11
2
WHY IS OIL SO IMPORTANT? .....................................................................................................................15
2.1
F
OSSIL FUELS A NECESSITY FOR THE INDUSTRIAL REVOLUTION
..................................................................15
2.2
T
HE BENEFITS OF OIL
......................................................................................................................................15
PART ONE â INTRODUCTION ..................................................................17
3
WHATâS THE PROBLEM WITH OIL USAGE? .........................................................................................18
3.1
L
ESS OIL IS FOUND
... .......................................................................................................................................18
3.2
...
AND THE DEMAND INCREASES RAPIDLY
....................................................................................................19
3.3
E
NVIRONMENTAL PROBLEMS
.........................................................................................................................20
4
WHY STUDY RUSSIA? .....................................................................................................................................21
5
THE IMPORTANCE OF RUSSIAN OIL FOR SWEDEN ..........................................................................22
5.1
O
IL USAGE IN
S
WEDEN
...................................................................................................................................22
5.2
S
WEDISH OIL IMPORT
......................................................................................................................................23
5.3
W
HY HAS THE SHARE OF
R
USSIAN OIL IN
S
WEDEN INCREASED
?..................................................................24
5.4
C
ONCERNS ABOUT FUTURE IMPORT POSSIBILITIES
........................................................................................24
PART TWO â RUSSIA ..................................................................................27
6
HISTORICAL OIL PRODUCTION IN FORMER SOVIET UNION .......................................................28
6.1
F
ROM EARLY OIL PRODUCTION TO
S
ECOND
W
ORLD
W
AR
(1870-1945) .....................................................28
6.2
T
URBO
-
DRILLING AND WATER FLOODING INCREASES PRODUCTION
............................................................29
6.3
S
OVIET
U
NION BECOMES
W
ORLD
â
S LARGEST OIL PRODUCER IN
1974 ........................................................30
6.4
T
HE FALL OF THE
S
OVIET
U
NION AND THE OIL PRODUCTION
(1991)...........................................................30
6.5
S
PECIAL DISCOVERY PATTERNS IN FORMER
S
OVIET
.....................................................................................31
7
THE OIL PRODUCING REGIONS IN RUSSIA ..........................................................................................32
7.1
V
OLGA
-U
RAL
..................................................................................................................................................33
7.2
W
ESTERN
S
IBERIA
..........................................................................................................................................34
7.3
T
IMAN
-P
ECHORA
............................................................................................................................................35
7.4
N
ORTHERN
C
AUCASUS
...................................................................................................................................35
7.5
E
ASTERN
S
IBERIA
...........................................................................................................................................35
7.6
S
AKHALIN
.......................................................................................................................................................36
8
CURRENT OIL PRODUCTION IN RUSSIA ................................................................................................37
8.1
O
VERVIEW OF THE
R
USSIAN OIL MARKET
.....................................................................................................37
8.2
P
RIVATE MAJOR OIL COMPANIES
....................................................................................................................37
8.3
S
TATE
-
OWNED COMPANIES
............................................................................................................................40
8.4
I
NDEPENDENTS
................................................................................................................................................40
8.5
F
UTURE PLANS OF
R
USSIA
..............................................................................................................................40
9
HOW MUCH OIL IS LEFT IN RUSSIA? ......................................................................................................43
9.1
C
LASSIFICATION OF OIL FIELDS
......................................................................................................................43
9.2
R
ESERVE ESTIMATES
......................................................................................................................................45
9.3
A
WORD ON
A
RCTIC OIL
.................................................................................................................................46
7 (100)
PART THREE â MODELLING....................................................................49
10
SCENARIOS AND INPUT DATA..................................................................................................................50
10.1
D
ESCRIPTION OF THE SCENARIOS
.................................................................................................................50
10.2
D
IVISION OF
R
USSIA INTO TWO MAIN REGIONS
...........................................................................................50
10.3
T
IME PERIODS
...............................................................................................................................................51
10.4
P
RODUCTION DATA AND CUMULATIVE PRODUCTION
..................................................................................51
10.5
O
IL LEFT IN
2006 ..........................................................................................................................................52
10.6
D
EPLETION RATE
..........................................................................................................................................52
10.7
D
OMESTIC OIL DEMAND
...............................................................................................................................54
11
THE HUBBERT MODEL â A FIRST ESTIMATE ....................................................................................58
11.1
T
HEORY
.........................................................................................................................................................58
11.2
O
IL LEFT ESTIMATE
(
VARIABLE
URR).........................................................................................................59
11.3
P
RODUCTION ESTIMATES
..............................................................................................................................60
11.4
P
RODUCTION ESTIMATES
â
DELAYED
H
UBBERT CURVE
.............................................................................60
12
THE DEPLETION RATE MODEL ...............................................................................................................62
12.1
W
HY USE DEPLETION RATE
? ........................................................................................................................62
12.2
I
NPUT PARAMETERS
......................................................................................................................................64
12.3
C
ALCULATION
...............................................................................................................................................70
12.4
O
UTPUT PARAMETERS
..................................................................................................................................70
13
DEPLETION MODEL RESULTS..................................................................................................................72
13.1
R
EFERENCE POLICY
......................................................................................................................................72
13.2
A
LTERNATIVE POLICY
..................................................................................................................................75
13.3
M
INIMUM
,
MEAN AND MAXIMUM VALUES
..................................................................................................77
13.4
S
UMMARY OF PEAK AND EXPORT STOP YEARS
............................................................................................79
14
DISCUSSION .....................................................................................................................................................80
14.1
D
EPLETION
R
ATE
M
ODEL VS
. H
UBBERT
C
URVE
........................................................................................80
14.2
M
ODEL PARAMETER IMPACT ON THE RESULTS
............................................................................................80
14.3
H
OW PROBABLE ARE THE DIFFERENT OUTCOMES FROM THE SCENARIOS
? ................................................80
14.4
F
ACTORS NOT TAKEN INTO CONSIDERATION IN THE MODEL
.......................................................................82
14.5
S
HORT SUMMARY OF RESULTS
.....................................................................................................................85
14.6
C
LOSING WORDS AND FURTHER STUDY
.......................................................................................................85
APPENDICES AND REFERENCES............................................................87
15
APPENDIX A: ENERGY USAGE IN SWEDEN.........................................................................................88
16
APPENDIX B: CALCULATIONS FOR THE HUBBERT MODEL........................................................90
16.1
O
IL LEFT ESTIMATE
.......................................................................................................................................90
16.2
P
RODUCTION
E
STIMATES
â
DELAYED
H
UBBERT CURVE
............................................................................90
17
APPENDIX C: MORE ABOUT THE DEPLETION RATE MODEL .....................................................91
17.1
C
ONNECTION BETWEEN DEPLETION RATE AND DECLINE RATE
...................................................................91
17.2
G
ROWTH RATES USED FOR CALCULATING THE DOMESTIC DEMAND
..........................................................93
17.3
F
URTHER DESCRIPTION OF THE INPUT PARAMETERS USED IN THE DEPLETION RATE MODEL
....................93
17.4
C
ALCULATIONS DONE BY THE DEPLETION RATE MODEL
.............................................................................94
REFERENCES ............................................................................................................................................................98
About oil
Aram MĂ€kivierikko
10 (100)
1
Units and terminology
To understand the world of oil, one must first know the oil âlanguageâ. This chapter will
discuss the usage of units and the different terms that are often used when talking about oil.
1.1
Units and prefixes
1.1.1 Oil amount measurement
Oil can be measured in weight or in volume. Crude oil that is extracted from the earthâs crust
does not consist of one single element. It is a mixture of hydrocarbons, and this mixture varies
depending on the source material from which the oil has formed. Crude oil also contains small
amounts of impurities, of which the most common one is sulphur. Vanadium is another
impurity that can have an impact in certain technical applications Two similar volumes of oil
can differ in density. It is therefore important to have some kind of a standard on how to
measure oil.
Since United States has been the driving country for oil production, the
barrel
has become a
de facto standard for volume measurement. This is also the unit of choice for this thesis.
The standard abbreviation for barrel seems to be â
bbl
â
2
. In this thesis â
bâ
is used.
1 b = 0.1591 m
3
= 159 l = 42 US gallons = 35 imperial gallons
â
3 fuel tanks of car (A.15)
1 kb = 1000 b
1 Mb = 1 000 000 b
1 Gb = 1 000 000 000 b
1 m
3
= 6.285 b
In Europe, oil is often measured in weight, and the unit used is normally metric tonnes.
1 metric tonne = 1000 kg = 1.102 short tonnes (USA) = 0.984 long tonnes (UK) = 2204
pounds (USA) = 35274 ounces (USA).
One problem is how to convert one metric tonne to barrels. As already mentioned, there are
different types of oil with different densities. BP
3
gives the following conversion factor on
their web site using the worldwide average gravity:
1 metric tonne = 1.165 m
3
= 7.33 b
(B.6)
2
bbl
stands for
blue barrel
. In the US they used to put the crude oil in
blue
barrels and the finished product in
red
barrels. (Source: mail conversation with C. Campbell)
3
BP; former
British Petroleum
but is as of 2001 simply called BP.
About oil
11 (100)
1.2
Terminology
1.2.1 Miscellaneous
Oil
In context of oil production, the definition from BP Statistical Review (B.4) is used:
crude oil, shale oil, oil sands and NGLs (natural gas liquids - the liquid content of natural gas
where this is recovered separately)
.
In context of oil consumption, the definition from World Energy Outlook (A.6) is used:
crude oil, condensates, natural gas liquids, refinery feedstocks and additives, other
hydrocarbons and petroleum products (refinery gas, ethane, LPG, aviation gasoline, motor
gasoline, jet fuels, kerosene, gas/diesel oil, heavy fuel oil, naphtha, white spirit, lubricants,
bitumen, paraffin waxes, petroleum coke and other petroleum products)
.
Oil reservoir
A subsurface porous and permeable rock body that contains oil, gas or both (A.1 p. 172).
Oil field
An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the
same individual geological structural feature or stratigraphic condition (A.1 p. 170).
Geological basin
A large geological area in which sedimentation is occurring or has occurred. Certain parts of
the basin might therefore have the required geological conditions to trap oil. Consists of many
oil fields.
Wildcat
A wildcat is an exploration borehole drilled when searching for oil or gas.
1.2.2 Reserve terms
Cumulative production
The
cumulative production
is the sum of all oil that has ever been produced until a specific
date. Cumulative production can be given for a field, oil basin, country or the world. Since the
oil mentioned here has actually been pumped up from the ground, production data is
usually
very reliable compared to the other terms presented below, but can be poorly reported in some
cases â especially for Russia.
Oil-in-place & Recovery Factor
Oil-in-place is the estimated total amount of oil that is in the ground before production has
started. For various reasons far from all of this oil can be recovered. Oil-in-place is usually
calculated on a field basis and in an early stage. The oil-in-place value is multiplied by a value
called
recovery factor
and results in an estimated URR for a single field (see below). Later in
a fieldâs production phase the URR is usually calculated with other techniques (C.3).
The average recovery factor increases with the size of the field as can be seen in Figure 1. The
world average is 29% and is predicted to rise with the usage of improved oil recovery
techniques.
Aram MĂ€kivierikko
12 (100)
Figure 1. Recovery factor for oil fields of different sizes. STOIP = âStock Tank Oil in
Placeâ â the estimated amount of oil in the ground. IOR = âImproved oil recoveryâ
(B.20)
Recoverable Reserves (Estimated future production from known fields)
The recoverable reserves are an estimate of how much
recoverable
oil is still left in the
already found oil fields
. It can only be an estimate since itâs impossible to know exactly how
much oil is still in the ground.
Because of this uncertainty, reserves are calculated with a certain probability. A reserve
estimate followed with, for instance, âP90â means that there is a 90% chance that there is at
least as much recoverable oil as the reserve estimate claims.
A great mess would occur if every oil company calculated oil reserves with different values
for the probabilities. Therefore three standardised probability ranges â Proven, Probable and
Possible â are used in most of the world. Russia, on the other hand, uses its own âABCDEâ
classification system, which is described in chapter 9.1.
Yet-to-find
Yet-to-find is an estimate of the amount of
recoverable
oil that exists in
fields that have not
yet been found
.
Ultimately Recoverable Reserves (URR)
URR is a concept with many names: Total Recoverable Reserves, Ultimately recoverable
reserves (shortened to URR) or simply âUltimateâ. The short form
URR
is most common in
this thesis.
The URR is an estimate of the total amount of
recoverable
oil that exists in the ground before
the production starts. In case of a single oil field, URR is defined as
About oil
13 (100)
URR (single field) = cumulative production + recoverable reserves
When talking about a region or a country, the URR refers to the total amount of oil that will
ever be produced from that region/country including yet-to-find fields:
URR (region, country) = cumulative production + recoverable reserves + yet-to-find
1.2.3 Production terms
Production
Production refers to the amount of oil that is produced during a certain time period (most
often a day or a year). In this thesis the following units are common:
kb/d (1 000 barrels per day)
Mb/d (1 000 000 barrels per day)
Gb/y (1 000 000 000 barrels per year)
1 Mb/d = 365/1000 = 0.365 Gb/y
1 Gb/y = 1000/365 = 2.74 Mb/d
Decline rate
The decline rate refers to production only. It is defined as the
negative relative change
of
production over a time period. Often a period of a year is used. The decline rate can be
expressed as a fraction (Formula 1) or as percent.
!
Last year's production â This year's production
Last year's production
Formula 1. Definition of decline rate (expressed as a fraction).
Example:
Assume a production of 1 Gb in year 2000 and 0.95 Gb in year 2001. The decline rate for year
2001 would then be (1 - 0.95)/1 = 0.05 = 5%
If the production is rising, the decline rate becomes negative.
Depletion rate
The depletion differs from the decline rate in that it takes into account the amount of oil that is
left. The depletion rate is defined as
this yearâs production
divided by
the amount of oil that is
left
.
!
Depletion rate
=
This year's production
Oil left at start of this year
Formula 2. Definition of the depletion rate (expressed as a fraction)
The amount of oil left is calculated by taking the
URR
minus
last yearâs cumulative
production
.
Aram MĂ€kivierikko
14 (100)
The depletion rate depends on the estimated amount of oil left. As more oil is produced, less
oil is left. At a
constant production
the
depletion rate grows
while the
decline rate is zero
.
The depletion rate can never become negative.
About oil
15 (100)
2
Why is oil so important?
The world is run by
energy
â not by money. Every living organism needs to convert energy to
a useful form to stay alive. As humans, we need to eat food to survive. What makes us
different from all the other species on planet Earth is that we have learnt to utilize energy for
more than just staying alive. During the history, we have become increasingly aware of how
to use all the different kinds of fuels and energy sources that nature provides us.
2.1
Fossil fuels a necessity for the industrial revolution
Without fossil fuels the world would probably look much different than it does today. The
rapid development in all sectors during the last two centuries would not have been possible.
Before the industrial revolution, water or wind was often used to drive machines such as
mills. The possible locations of machines that required lots of power were therefore limited.
In the early 1700âs an early steam engine was invented
4
. It was run on coal, and could now be
located almost anywhere. It became widespread after James Watt had modified it to drive
rotating machines and greatly reduced its coal usage. These improvements paved the way for
mass-producing factories and locomotives. The steam engine was later replaced by the
internal combustion engine that is used in cars and airplanes.
2.2
The benefits of oil
There is no such thing as a "perfect" energy source â there are problems, more or less severe,
with all energy sources. Some examples:
a)
Not enough local supply (wood)
b)
Hard and dangerous to extract (coal)
c)
Hard to transport efficiently (natural gas)
d)
Hard to store in an efficient way (electricity
5
)
e)
Creates toxic waste (nuclear power)
f)
Inefficient conversion (solar energy)
g)
Environmental problems: pollution at land, sea and air (any combustion).
h)
Large changes in landscape (all of the above â more or less)
The need then arises to compare the advantages and disadvantages of each energy source. The
problem is that at the discovery stage, it is nearly impossible to know what kinds of future
problems will arise.
When oil was discovered, the benefits highly outnumbered any problems. Oil can be used for
many things such as production of plastics, but below oil as a
fuel
is discussed.
-
Oil, and any product derived from oil, has a very high energy density, even higher
than that of coal and peat (Figure 2).
-
Oil is in liquid form at room temperature and atmospheric pressure. It is therefore
easier to store, transport and use than for example coal or wood. The burning process
can also be automated in a much simpler way.
4
The Greek inventor Heron invented a kind of steam engine around 200 BC, but it was probably not used to do
any useful work.
5
Electricity is strictly speaking not an energy
source
but an energy
carrier
. It is always generated from some
other source such as nuclear power, hydropower or solar cells, and stored in for example water in dams as
gravitational potential energy or in batteries as chemical energy.
Aram MĂ€kivierikko
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-
Oil leaves almost no waste products after burning
-
Oil is not too dangerous to handle.
-
Oil is collected in fields and can be extracted by simply drilling some wells and pump
it up, instead of in case of coal digging large coal mines.
Figure 2. Energy density of fuels. Oil-based fuels are shown in black. Moisture
percentage is shown in parenthesis. Mean values are used for heating oil and diesel.
Natural gas has an energy density of around 10 kWh/m
3
at atmospheric pressure and
temperature. (B.21)
With all these benefits it is no wonder that oil has become the world's largest energy resource.
We have been living in a "golden age of oil" with cheap, (relatively) easily accessible oil
(A.3). The oil is predicted to hold its important role at least a few decades into the future
(
Figure 3
), but this âgolden ageâ will eventually come to an end. The end of the golden age is
not about
running out of oil,
but rather about the problems that arise when the
naturally
limited oil production peaks, starts to fall
and as a consequence
canât meet the oil demand of
the world
.
Figure 3. Fuel share of world primary energy demand. Source data: A.6
p. 67
Part one â Introduction
Aram MĂ€kivierikko
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3
What
â
s the problem with oil usage?
The main problem with oil usage is that less oil is found while the oil demand is constantly
rising. Also, the oil causes environmental problems.
3.1
Less oil is found...
The search for oil on an industrial scale has been performed for more than a century. In the
50âs and 60âs there were still vast areas left to prospect for oil. When prospecting started in a
specific area, the largest fields were found early â they were the easiest ones to spot. These
large discoveries made people optimistic. Nobody thought that finding oil would become a
problem in the near future.
In 2007, most of the world has already been prospected. The probability of finding large fields
becomes smaller. The exact amount of oil discovered varies from year to year, but the
downwards-pointing trend compared to the 60âs is clear â see Figure 4.
Figure 4. Global annual discoveries of both oil and condensate, and oil production in
Gb. Source: A.10 p. 70
3.1.1 Energy returned on energy invested
One aspect worth considering is: how much energy is spent to actually get up the oil from the
ground? The oil doesnât come from the ground for free. Energy is spend in prospecting,
drilling, pumping up the oil, transports, refining and so on. This is the concept of Energy
Returned on Energy Invested (ERoEI). If an energy source has an ERoEI factor of 1, all
energy is used for extracting new energy. Production from conventional oil fields has an
ERoEI of more than 50 (B.19). Unconventional oils such as oil shale and tar sands generally
have a much lower ERoEI than oil. As the conventional oil production starts to drop and
alternatives are sought for, the unconventional sources will not only take longer to get on-line,
smaller amounts of energy will be returned as well.
Part one â Introduction
19 (100)
3.2
... and the demand increases rapidly
Even though there is still a lot of oil left, the usage of oil increases continually. Since the
middle of the 1980âs (with a few exceptions), the oil production per year has exceeded the
discovery (Figure 4). In other words: we canât find enough new reserves to cover our
consumption, and are therefore forced to rely to a large extent on the huge reserves found
earlier. This canât go on forever.
Countries like China and India are developing rapidly. If the population in these countries
would start to use as much oil as we do in the industrialized countries, the worldâs oil supplies
would end very fast â let us study the following quick example where USA and Europe are
grouped together to represent a kind of a mean usage for the industrial countries.
Todayâs worldwide oil consumption is about
84 Mb/d
(WEO 2006).
-
USA and Europe use about 20.6 + 14.4 =
35 Mb/d
of oil.
-
USA and Europe have 330 + 730
â
1100 million inhabitants. (B.36, data from year
2005).
-
The mean oil usage for USA and Europe is thus
!
35
1100
"
0.032
b
d
#
person
-
The world has a population of 6.5 billion people. If the rest of the worldâs population
would use as much oil as USA and Europe, the world consumption would be
!
0.032
"
6.5
"
10
9
b
d
"
person
"
people
#
$
%
&
'
(
=
208Mb/d
â about 2.5 times todayâs consumption!
Probably no one believes that oil consumption is going to double within short as in this
example, but still itâs crystal clear that oil demand will increase in a short time perspective.
In the long run, the situation might change. Often the production of a natural resource is
driven by supply and demand. If the demand rises, the price of the resource goes up. It then
becomes economically viable for the producers to expand production to areas that were earlier
too âexpensiveâ. Production increases to meet the demand at the new price point. This is true
as long as the production is limited by the amount of money that is spent. But since the
production of oil is very much limited by natural constraints, this economical theory only
applies until the natural constrains are reached. After that, it will simply be impossible to
supply the world with the amount of cheap energy that many people are used to no matter
how much money the oil companies spend. This phenomenon with a peaking oil production in
combination with an increasing demand is known as
peak oil
. Robelius believes that the peak
production will occur somewhere between 2008- 2018 (A.10).
Oil is a crucial fuel mainly in the transport sector; electricity and heating can be provided in
many other ways. If no viable substitute(s) to oil are found in time, the amount and length of
transport is forced to decrease as the oil becomes scarce and the oil price increases. Transport
times will increase as the goods they are re-routed from trucks and flights to railway and ships
where possible. Local food production will become much more important as import from far-
away countries will cease to be economical. Leisure travel â especially by air â will decrease.
There are organizations that try to make possible future scenarios for oil demand of which the
International Energy Agency is one of the most important.
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3.2.1 Future oil demand predictions by International Energy Agency
International Energy Agency and World Energy Outlook
World Energy Outlook (WEO) is a yearly report from the International Energy Agency (IEA)
where the worldâs energy production and demand a few decades into the future is estimated.
Estimates for many different energy sources are made. Conveniently enough an
oil market
outlook
is a part of the report.
In the 2006 edition of WEO the forecast period lasts until year 2030. Two scenarios are
calculated: the
reference scenario
and the
alternative policy scenario
.
WEO 2006 - Reference Scenario
In the reference scenario, the energy production and consumption of the world will evolve
like âbusiness as usualâ. Not too many measures are made to try to decrease the consumption
of hydrocarbons (oil, coal, gas). The hydrocarbon demand â and more specifically the
oil
demand â therefore grows.
The worldâs oil demand is predicted to rise by an average of 1.3 % per year during the period
2005-2030. This means that the demand will increase from 83.6 Mb/d in 2005 to 116.3 Mb/d
in 2030 â an increase of almost 33 Mb/d (
â
40%)!
WEO 2006 â Alternative Policy Scenario
The alternative policy scenario is based on a much more aggressive reduction of hydrocarbon
usage in the world. According to the report this is only possible if the politicians start making
some quite drastic measures. IEAâs reason for making this scenario is not related to peak oil,
but rather to the growing political concern regarding climate change.
The oil demand will rise with 0.9% per year and reach 103.4 Mb/d in 2030 â an increase of
almost 20 Mb/d (
â
24 %).
3.3
Environmental problems
Oil causes problems for our environment. The most widely discussed problem is that of the
increasing greenhouse effect. When any fossil fuel such as oil is combusted, carbon dioxide
(CO
2
) is released to the atmosphere. Carbon dioxide is a greenhouse gas, which means that it
reflects specific wavelengths of the heat radiation emitted by the earth back towards the earth,
and thus keeps the temperature up. The Intergovernmental Panel on Climate Change (IPCC)
has made different scenarios that predict a 1.5 to 4°C global temperature increase in year
2100. However, IPCC have based those scenarios on burning of amounts of hydrocarbon that
might not be available (A.13).
Another environmental problem is that oil itself is destructive for plants and animals. Most
attention is often given to leaking oil tankers, but smaller oil spills on land can also be
problematic (B.27).
Part one â Introduction
21 (100)
4
Why study Russia?
Russia is currently the world's second largest oil exporter by large margin (Figure 5). It
exports slightly less than 7 Mb/d. As a reference, the largest exporter Saudi Arabia exported
about 9 Mb/d in 2005. The third largest exporter is Norway with 2.7 Mb/d in 2005 (B.10).
Let us assume that the world oil demand will be 33 Mb/d (or 20 Mb/d in the alternative policy
case) higher in year 2030 as discussed in chapter 3.2.1. Saudi Arabia, the world's largest oil
producer and also the largest oil exporter, might increase their oil production with 2 Mb/d
until 2016, and then hold that level at least until 2033 (B.3 p 24). Norwayâs production has
been falling since 2002 (BP) which means that their export will most likely decrease in the
future. So where will the remaining 31 Mb/d (or 18 Mb/d as in the alternative policy scenario)
be produced? Will it be possible to meet the demand?
The Russian oil will start to increase its importance as the production capacities of other
countries fall. In this thesis, some future scenarios for Russian oil production and oil export
are studied. How much will Russia be able to export? Will Russia be able to increase its
production level enough to suit the need of the importing countries â and for how long?
Russiaâs domestic consumption is increasing and will continue to increase in the future; how
will that affect the export capability? The goal is not to come with exact predictions, but to
make reasonable educated guesses.
Figure 5. Net oil export by country (A.2). The quoted values might not be 100% accurate
since they are calculated by taking the production minus the domestic usage.
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5
The importance of Russian oil for Sweden
First, the energy usage of Sweden is discussed with focus of oil usage. Sweden doesnât
produce oil itself, so the oil needs to be imported. The share of imported crude oil from Russia
increases rapidly.
5.1
Oil usage in Sweden
Sweden is quite fortunate when it comes to energy supply. Most electricity comes from
nuclear power and hydropower. The share of fossil fuels (oil + coal + natural gas) has
decreased from more than 80 % to about 37 % in 2004 since the 70âs (Appendix A Figure
40).
The oil usage in particular has almost been cut by half (Figure 6). The residential and service
sector has changed from being oil-intensive to being dominated by mainly bio-fuelled district
heating and electricity. The same trend is true for the industry sector, which today mainly uses
electricity and biofuels.
As in most other countries, the transport sector is the largest user of oil products. In Sweden it
accounts for over 70% of the total oil usage (Figure 6). It is the only sector where oil usage
has increased. To find viable alternative fuels is a great challenge due to the superiority of oil
as an easily transportable fuel with a high energy content.
Appendix A shows the energy usage divided by energy source for Sweden in total and the
residential/industry/transport sector.
Figure 6. Final oil use in Sweden 1970-2005, excluding bunker oils for domestic sea
transports. Source data:B.33
Part one â Introduction
23 (100)
5.2
Swedish oil import
Above it was shown that even though the oil usage in Sweden has decreased, it is still a large
part of the total energy usage. Sweden is not an oil producing country and thus needs to
import oil. Since the finding of oil in the North Sea, a large part of Swedish oil has been
imported from Norway. But 2002 the Norwegian oil production started to drop (B.4), and
Sweden has been forced to increase its imports from other countries â most notably Russia. In
2001 Russia accounted for only 5% of Swedish import. In 2005 the same figure was 35%. In
only four years, Russia has become the most important oil exporter for Sweden (Figure 7)! In
2006 the growth in the imported percentage from Russia has slowed down, but there is still a
growing trend.
Figure 7. Percentage of Swedish crude oil import by country. Data source: B.29
A side note: the large import from Denmark might look a bit strange, since Denmark is not
known to be a large oil producer. However, a small part of the oil basin that the Norwegians
use reaches over to Denmarkâs side of the border (C.1). Denmark produced 0,37 Mb/d in
2005, or about 12% of the Norwegian production (B.4). Sweden then imports a large
percentage of Denmarkâs oil production. However, the Danish production seems to have
peaked in 2004 (B.5), so Russian oil might grow in importance even more.
In 2006, Sweden imported 196 Mb of oil products. Out of this amount 147 Mb or 0.40 Mb/d
was crude oil. Of the crude oil, 36% or 0.14 Mb/d came from Russia (B.29 2006). This is
slightly less than 1.5% of Russiaâs total production of 9.5 Mb/d in 2005 or about 2 % of
Russiaâs export of 6,7 Mb/d in 2005, so Sweden is and will remain a small customer for
Russia.
Far from all of the imported oil products are used domestically in Sweden. The imported
crude oil is refined to end-user products in high-quality refineries placed along the Swedish
east and west coasts. In 2006 the domestic consumption
6
of end-user oil products was 100 Mb
while 80 Mb was exported (B.29 2006). If only the domestic oil consumption is considered,
oil imports could theoretically be cut by half.
6
Including international bunker oil (fuel oil used by ships with non-domestic destinations)
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5.3
Why has the share of Russian oil in Sweden increased?
There are three main reasons for why the Russian oil import has grown enormously during the
last few years:
- Improved handling of high-sulphur oil
- Itâs cheaper
- Faster delivery and better credit time
Improved handling of high-sulphur oil
The oil that is delivered from Russia is actually a mix of two different oil types. One is of
high quality with low sulphur content. The other type has more sulphur. Oil with high sulphur
content often consists of a larger part (50%) of heavy fractions, which means that a large part
of it has to be cracked (split into shorter hydrocarbons) to get the end products that are
needed. If the sulphur is not removed before cracking, it destroys the catalyst in the cracking
process. (C.6). Not all refineries in Sweden have always had equipment to handle large
amounts of high-sulphur oil.
Itâs cheaper
Russian oil is currently cheaper than most other oil partly because of its lower quality / high
sulphur content. Since the refineries now can use Russian oil in larger volumes than before,
why pay extra for better oil when the Russian oil suits your needs?
Faster delivery and better credit time
The oil shipping capacity of the Primorsk shipping terminal in the Gulf of Finland has been
improved, From there, oil can be delivered to Sweden in about 3-4 days compared to oil from
the Middle East that takes about one month. Since the credit time for both types of oil is 30
days, it is more economic to choose the oil with the fastest delivery â that way you can use the
oil before you need to pay for it.
(B.22, C.4)
5.4
Concerns about future import possibilities
As discussed in section 5.2, Sweden is a small customer for Russia. Will Russia still export to
Sweden when the amount of exportable oil starts to drop and larger, more important
customers would like to increase their import? This question is difficult to answer.
Also, what will happen with Russian oil prices in the future? Russia is a major player in the
oil world, and its importance will most probably increase in the future â not just for Sweden,
but also worldwide. As many countries get more and more dependent on Russian oil, Russia
could soon be in a close-to-monopoly situation with few other exporting countries left. They
can then increase the oil price without risk of loosing much export.
Actually, price disputes between Russia and importing countries have already occurred on the
gas side. On January 1:st 2006 Russia closed a major gas pipeline that goes through Ukraine
to other European countries such as Germany, Italy and Poland for three days. According to
Russia, the reason for the closedown was that Ukraine, as a former Soviet republic, had been
Part one â Introduction
25 (100)
paying heavily subsidized gas prices compared to the market prices. The Russian state-owned
gas company Gazprom now wanted Ukraine to start paying market prices. Ukraine agreed to
eventually reach market price levels but wanted to ramp up the price increase over a few years
instead of a sudden price jump â a quite fair request since Russia themselves did ramp up their
domestic prices after the fall of the Soviet Union, see chapter 14.4.2. Russia didnât agree and
closed the valves. Although they did this for only a short time and thus didnât affect the
European countries that have oil reserves for a couple of weeks to months (B.31), this still
shows the dependence on Russia.
Another recent (2007-05-02) stop of oil and coal deliveries from Russia to Estonia could be
seen as a way for Russia to use its energy as a political âweaponâ. Russia claims that the stop
has occurred due to technical reasons, but others believe that they wanted to mark that Estonia
shouldnât have removed a Soviet-time World-War II memorial statue. (B.32)
In the light of these events, it would not be wise of Sweden to become too dependent on
Russian oil. A slightly increased import from Russia might be feasible, but Sweden should
continue importing oil from other countries as long as possible â it is always good to have
options.
Sweden should also avoid building pipelines for the purpose of oil or gas import. The main
reason for this would not be mistrust against Russia, but the short-sightedness in
creating/expanding an energy system based on fossil fuels.
Actually, Sweden is on a good track of becoming less oil-dependent. The last (2002-2006)
government started an expert group called
Kommissionen mot oljeberoende,
freely translated
âThe Commission against oil dependenceâ. The group was given the task to find ways that
would break the Swedish oil dependence in 2020. They finished their report in summer 2006.
The key points were to improve energy efficiency with 20%, to get rid of the oil need for
heating purposes, to decrease the oil use in the industry by 25-40% and last but certainly not
least decrease the petrol and diesel use in road transports by 40-50% (B.30). Sweden is a
country with big renewable natural resources and lots of world-leading research on renewable
energy sources. If the new government continues on the same track, the vision could become
true if just enough money and resources are spent.
In summary: Sweden still needs oil even if the usage is decreasing. Russia has quickly
become the most important oil exporting country for Sweden!
Part two â Russia
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6
Historical Oil Production in Former Soviet Union
6.1
From early oil production to Second World War (1870-1945)
Oil has been produced in the former Soviet Union for quite some time. For centuries, people
in the Baku region in Azerbaijan (Figure 8) used rags and buckets to collect oil that had
seeped to the surface. Later on they started to dig pits by hand. Industrial oil production
started in the 1870:s, greatly helped by foreign investors such as the Swedish Nobel family.
(A.5)
Figure 8. Map of Baku (capital of Azerbaijan) and nearby countries
The increased crude oil production was a response to an increased demand of kerosene, a
distilled product that was mainly uses in lamps. It replaced other more expensive lamp fuels
such as whale oil. The Nobels built facilities for kerosene distillation, and established trade
routes. The oil production rose slowly to a start, but accelerated towards the end of the 19:th
century. Soviet Union was the largest oil producer in the world between 1898 and 1901.
The major part of the henceforth produced oil had come from shallow parts of two supergiant
fields. This easily available oil now started to decline, and it was at that time impossible to
extract oil that was buried deeper than about 700 m. Oil was found in other areas and
dampened the decline.
Then came the First World War. Between 1-3 three million Russians died, among them two
thirds of the workforce in the Baku fields; many workers had joined the army. Also many
industries were shut down or destroyed (A.5). Even so, Soviet Union was the second largest
oil producer in the world until 1918 (A.14). That year the new Soviet government
nationalized oil, which made many foreign investors to leave the country. This combination of
decreased demand and decreased production capacity made the oil production drop by half
(Grace).
Part two â Russia
29 (100)
In 1921, foreign investors were allowed again. The oil prospecting spread to new areas. New
technology was introduced. Oil production soon recovered, and reached a new peak of 238
Mb/y in 1941.
In the Second World War, Soviet forces had to sabotage their own oil fields in Caucasus to
prevent the Germans from using them (A.5). Oil production dropped by about 30 % to 167
million barrels per year (A.14).
Figure 9: Estimate of Soviet oil production 1870-1948. See chapter 10.4 for sources for
the data used.
6.2
Turbo-drilling and water flooding increases production
After the war, the production recovered and increased faster than ever when new fields were
taken into production. The Volga-Ural region, including the giant Romashkino field,
accounted for the largest increase (Figure 10, Figure 12). This huge production increase
would not have been possible without two new techniques, namely turbo-drilling and water-
flooding.
Turbo drilling enabled the Russians to drill the harder rock of the Volga-Ural region using
shafts made of the available low-quality steel. By placing the motor close to the drill, the
stress on the shaft became much lower compared to having the motor at the surface.
Nowadays better steel and much more advanced drilling techniques are used.
Water flooding counters the natural decrease in production (caused by pressure decrease) that
occurs for a producing field. By inserting water, the oil is pushed towards the wells. If done
right, this method increases both production speed and the total amount of oil that can be
recovered from the field. It is better than just using the natural pressure or pumps.
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6.3
Soviet Union becomes World
â
s largest oil producer in 1974
In 1960 Soviet Union once again became the second largest oil producer in the world. In 1974
it surpassed even USA with a production of 9 Mb/d (A.5). Peak production occurred in 1984
with about 11.2 Mb/d (A.5).
In the middle of the 80âs, Saudi Arabia increased its oil production, which made the world
prices drop. Some believe that this was part of a secret US strategy to bring Soviet Union
down (A.11). Strategy or not, the price drop was a hard blow against Soviet Union; the
important revenues from oil export shrank. One theory of the small production dip in the
middle of the 1980âs is that less oil was produced because the export would not have been
profitable. But according to Grace, the production drop made the Soviets to start an extensive
(and expensive) campaign to maintain the high oil production, so there might have been
technical production problems as well.
6.4
The fall of the Soviet Union and the oil production (1991)
As a result of the campaign, the oil production increased again. It reached the old peak level
and might have increased even further â but then came the fall of the Soviet Union. During
the period 1990-1995, the production dropped by almost 50 % to about 5.8 Mb/d and then
remained nearly constant for the rest of the decade. It is important to note that the fall in
production was not due to Russia running out of oil. Rather, it was mainly due to a lack of
investment in combination with usage of old technology (A.7). Many wells didnât get the
maintenance they needed and simply had to shut down (A.5).
Figure 10: CIS oil production by region (Source: B.11.
Mbo/day
= 1000 barrels of oil per
day.
This flat trend was broken around year 2000. New technology and new investments were
made, which led to an increasing production. According to Yukos, one of the largest oil
companies in Russia at that time, utilizing new drilling and production techniques for new
Part two â Russia
31 (100)
wells made these wells produce about three times the Russian industry average (A.5).
However, the production shouldnât be rushed. Any short-term production increases should be
balanced against the possibility of damaging the field and lowering the ultimate recoverable
amount of oil. This balancing was not always done right â many old-time Russians thought
that Yukos was ârapingâ their reservoirs (C.3). One should also remember that a faster
production generally means a faster depletion.
6.5
Special discovery patterns in former Soviet
In most oil-producing countries the prospecting and production of oil is made by profit-driven
oil companies. Wildcats are drilled in the most promising areas. The correlation between
discovery and production is probably quite noticeable.
In the former Soviet with its communist regime, the oil prospecting was completely separated
from the oil production. This meant that the prospecting was not limited by profit constraints
(A.5). Every single wildcat drilled didnât have to â or wasnât expected to â lead to a discovery
of a new oil field. Instead, the engineers could drill samples to analyze the rocks in areas
where oil was not necessarily expected and thus make better estimates of the actual location
of the oil (C.2).
The Soviet workers got a âcold climateâ bonus if they worked north of the 60:th latitude
(C.2). It might be a coincidence, but especially when looking at Western Siberia in Figure 11
(in chapter 7 below), the majority of the found oil and gas fields are indeed situated above the
60:th latitude. It is no question that the majority of oil is there, but it would be interesting to
know if the southern part of Western Siberia basin is prospected as thoroughly as the northern
part.
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7
The oil producing regions in Russia
Former Soviet Union, or CIS
7
as it is nowadays called, can be divided into oil-producing
regions in different ways. The division (excluding Arctic) shown in Figure 11 is suggested by
IHS
8
Figure 11. Oil basins and exploration areas. Source map: A.7 p. 14
- Black dots: the oil and also gas fields that have been found to date. They might be
producing, not yet producing or depleted.
- Brown, dark green and light green areas: geological oil basins
-
Mature (brown) â Northern Caucasus, Volga-Ural, Timan-Pechora, Western
Siberia â the area has been thoroughly prospected for oil. Production has been
going on for quite some time. It is unlikely to make any large findings of oil in the
future.
-
Developing (dark green) â Eastern Siberia â An area that have not been that well
prospected. Only a small part of the existing oil has been produced.
-
Frontier (light green) â Arctic, Sakhalin â The areas have not been thoroughly
prospected. New oil findings can be expected. Mainly areas that are technically
difficult to produce such as deep off-shore
Source: C.5
7
CIS, Commonwealth of Independent States, an alliance of Russia and the former Soviet states, formed after the
fall of Soviet Union
8
IHS Energy, part of IHS (Information Handling Services). Formerly called Petroconsultants.
Part two â Russia
33 (100)
Each region will be described below, but the emphasis will be on the two most important
regions according to Figure 10: Volga-Ural and Western Siberia.
7.1
Volga-Ural
Before the Second World War, most Russian oil was produced in the Baku region. In 1929 a
drilling crew accidentally found oil when searching for potassium at the western edge of the
Ural Mountains. Some more oil prospecting was made, but only a few small and widely
spread fields were found. This pattern hinted at great oil amounts to many geologists, but not
until the production loss during the second world war (chapter 6.1) did the government
explore Volga-Ural further; a safer area for oil production far away from the battlefield was
needed. Deeper drilling revealed much larger oil accumulations. The production from the
region started to grow rapidly. (A.5 p. 16-17)
After the Second World War, Volga-Ural quickly became the most important oil-producing
region in the Soviet Union â a position it held for over three decades until the end of the 70âs
(Figure 10). A major part of the production has come from one single giant field in the Tatar
region:
Romashkino
. Figure 12 shows that the production of the Volga-Ural region quite
closely follows the production from Romashkino.
Romashkino was discovered in 1948 and would with a URR of 17 Gb (A.10 p. 79) be the
largest oil field in Russia for decades. At the time of discovery, it was the largest field in the
world! This didnât go unnoticed by the leaders in Moscow. Huge amounts of resources were
spent (A.5 p. 14). Production started in 1953 and gave a huge boost to the Soviet Unionâs oil
production. In the middle and late 60âs, the even larger resources of the West Siberian basin
caught the interest of the government. Volga-Ural lost much of its funding, which led to a
production decrease (A.5 p. 15). Romashkino peaked in the end of the 60âs. The rest of the
region followed half a decade later. In about 20 years the Volga-Ural production dropped by
65%.
Since the middle of the 90âs Volga-Ural production has been quite flat due to new interest in
smaller and medium-sized fields. The region is close to pipelines, refineries and potential
customers and is still the next largest oil-producing region in Russia (Figure 10). It will
probably never reclaim its leading role unless new, large oil reserves are found. This is highly
unlikely, since when oil is prospected for, the largest oil accumulations are almost always
found first. Grace puts it this way: âThis change in mix from basin output dependent on giant
fields to a growing role for medium and small fields is the hallmark of high exploration
maturity â meaning the basin does not have much undiscovered oil left to give.â (A.5 p. 19)
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34 (100)
Figure 12. Volga-Ural production (Source: B.11)
Mbo/day
= 1000 barrels of oil per day.
7.2
Western Siberia
Western Siberia is the currently most important oil-producing region in CIS. In the 70ÂŽs a
large part of the production came from the giant Samotlor field, but as Samotlor production
has declined, production has shifted to an increasing number of smaller fields. The region has
the greatest future potential; the region is responsible for the upswing in oil production during
the latest years and holds more than two thirds of the remaining oil in Russia (B.11). Western
Siberia also contains huge gas reserves.
As early as 1932, I.M. Gubkin, also known as the father of Soviet petroleum technology,
suggested that Western Siberia would be a very probable place to find oil. But it is not a
particularly nice place. Firstly, the distances are large, and the region is far away from the oil
consumers. Secondly the climate is severe. A large part of the region is essentially an Arctic
swamp with two periods: flood and freeze. In the winter, the Ob River that flows north into
the Ob Gulf freezes. In the spring, the southern parts of the river melt, but the northern parts
are still frozen. The spring flood canât take the proper route to the Ob gulf and instead floods
the oil basins, most of which are close to the river.
Due to the problems described above, the government wasnât very keen to allocate resources
for Western Siberia. But as many fields were large and easy to detect, the resource need
turned out to be moderate.
Samotlor â Russiaâs largest oil field with more than 27 Gb of recoverable oil â was found in
1965, and production started the same year. Samotlor played an important role in the major
economic upswing in Russia during the decades that followed. Up to the middle of the
eighties it produced more than half of Western Siberiaâs output (Figure 13). The field peaked
around 1980. After the fall of the Soviet Union, production fell fast, but has recovered slightly
since 2002. Samotlor is still estimated to have about 30% of its recoverable oil left (A.5), so
with some investments and maintenance the field should in theory be able to at least keep a
constant production for some time before the natural limits kick in.
Part two â Russia
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Figure 13. Western Siberian oil production (Source: B.11).
Mbo/day
= 1000 barrels of
oil per day.
7.3
Timan-Pechora
Timan-Pechora is the third largest oil producing region in Russia but is small compared to
Western Siberia and Volga-Ural (Figure 10). The region is situated in the north with a
shoreline that consists of both the Barents Sea and the Kara Sea. Close to 200 oil fields have
been discovered. The region has recoverable oil reserves of about 10 Gb. (B.9)
7.4
Northern Caucasus
This is the region where much of the early Russian oil production took place. Azerbaijan with
its capital Baku is situated just below this region. The region is still producing, but the amount
is negligible compared to the country as a whole.
Something that does not directly have to do with the Northern Caucasus region but is worth
mentioning is the Kashagan field. It is situated just east of the Northern Caucasus region, in
the northern part of the Caspian Sea that belongs to Kazakhstan. Kashagan is assumed to be a
supergiant field and is currently assumed to hold at least 13 Gb of recoverable oil (B.1). The
field has proven to be much more difficult to produce from than what was initially believed.
Production was to start in 2005 but is now estimated to 2008-2009. The production will
probably go to China â they are planning to build an separate pipeline to avoid transfer
through Russia. Since Kashagan will probably not add to Russian production it is not studied
closer in this thesis.
7.5
Eastern Siberia
Eastern Siberia is the largest land-based area in Russia that is still not fully explored (Figure
11). The area could hold more than 16 Gb of oil (B.9).
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7.6
Sakhalin
Sakhalin is situated in eastern Russia, just to the north of Japan. The current oil production is
quite small compared to the rest of Russia. However, the region has quite a lot of gas. Most
findings are off-shore.
As a side note, Japan doesnât have any domestic fossil fuel resources and is interested in
importing part of the oil and gas found in Sakhalin.
Part two â Russia
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8
Current oil production in Russia
8.1
Overview of the Russian oil market
Before the fall of the Soviet Union, the oil was produced by about 40 administrative units that
all were responsible for a certain region. They were all divisions of the Soviet Ministry of Oil
(A.5p 105). The production companies were only responsible for the production itself. The
prospecting was made by the Ministry of Geology, and still other administrative units
supplied the production units with equipment to keep the fields going. The producing units
sent the oil away to refineries controlled by another ministry. Money was given from the
government. Oil prices, costs and production rates werenât connected.
After the fall, the situation started to change. Larger companies started to buy smaller ones.
Many companies became privatized. Most companies now became vertically integrated: like
most western companies, they controlled the whole process from prospecting, production,
refining and marketing of the finished products. In 2002 there were 13 of these vertically
integrated companies (VIC:s) in Russia.
The oil companies can be divided into
-
Private companies
-
Regional companies
-
Independent companies
-
State-owned companies.
As a note of interest,
neft
means oil and
gaz
means gas. Many of the companies mentioned
below thus have names that end in âoilâ or âoil and gasâ.
8.2
Private major oil companies
The four largest private companies â Lukoil, Sibneft, TNK-BP and Surgutneftegaz â will be
discussed below. Yukos â one of the largest companies until a few years ago â is also
mentioned. As can be seen in Figure 14 and Figure 15, these companies stand for a large part
of the total Russian production and the proved reserves.
8.2.1 Lukoil
Since the fall of the Tsar Nicholas II in 1917, the Russian oil production had been controlled
by the State. The situation changed a few weeks before the fall of the Soviet in December
1991 when the oil companies Langepasneftegaz, Uraineftegaz and Kogalymneftegaz joined.
The private oil company Lukoil was born. (A.5 p 76)
Lukoil was the largest oil company in Russia for a decade after the fall and is still among the
leaders. From the start, Lukoil used the large western oil companies as a model â companies
that took care of everything from prospecting to selling the finished oil products to end
customers (A.5 p. 111). Lukoil was the first Russian oil producer to list its shares on a western
exchange.
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Western Siberia is the companyâs main production region with 65% of the production and
53% of the reserves. The Timan-Pechora region is also interesting; Lukoil has bought up
many smaller companies from there. (B.17)
In 2005 Lukoil produced about 1.8 Mb/d. They currently forecast an increasing production
that will reach 2,6-2,9 Mb/d in 2017. (B.18 ,p. 16).
8.2.2 Sibneft / Gazprom Neft
Sibneft is a company that has had a remarkable growth in production the last years (5% 2000,
20% 2001, 28 % (!) in 2002, 19 % in 2003). There were far-reaching plans to merge Sibneft
with Yukos, but the Yukos affair (see 8.2.5) changed it all. Sibneft is still quite small
compared to the others, and it needs money to make investments for the future. (A.5) Today
Sibneft has been acquired by Russiaâs largest gas company Gazprom (in fact âpromâ is short
for company, so Gazprom means âgas companyâ) and is called Gazprom Neft. Sibneft is still
operating independently. (B.13)
8.2.3 TNK-BP
TNK (Tunyen Oil Company) was started in 1995. They have been expanding a lot during
1998. TNK exports lots of oil through pipeline to Germany and Poland. (A.4)
In 2003, TNK merged with BP. This resulted in an improved management and an increased
oil production (Figure 14).
The main asset of TNK-BP is the Samotlor field. With the introduction of new technology
and better maintenance the production from Samotlor has during 2001-2004 increased by 30-
50 kb/d each year. However, this kind of increase canât be expected to continue for too long.
(A.5 p. 142)
8.2.4 Surgutneftegaz
Surgutneftegaz existed already during the Soviet times. Its primary task was to exploit
Federovskoye, the second larges field in Western Siberia. It became a vertically integrated
company in 1993 (A.4), but remained conservative compared to the other companies: it didnât
merge with other companies, only had a single refinery which served domestic customers, had
an executive board with only Russian members and so on. (A.5 p. 134). A major part of the
produced oil is used in domestic industries, but the company is also exporting oil. (A.4)
8.2.5 Yukos
Yukos was formed in 1993 as a merger of smaller companies. It was very West-friendly and
was the first company that adopted the western reporting standards.
The so-called Yukos Affair has shaken the company quite badly. Yukos former chief
executive Mikhail Khodorkovsky was sent to jail in 2005. Observers believe the main reason
to be Khodorovskyâs sponsoring parties that were against Putin in the 2003 elections (B.14).
The company was sentenced to pay back $30 billion in tax bills and has as of May 2007 sold
off all its assets to foreign companies (mostly to Rosneft) to cover its debts. Yukosâ days as an
oil producing company is over. (B.14)
Part two â Russia
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Figure 14. Oil Production for the major Russian oil companies (left y-axis). The summed
production of the major companies compared to the total Russian production (right y-
axis) (Source: A.5 and the company homepages)
Figure 15. Oil reserves for the major Russian oil companies (left y-axis). The summed
reserves of the major companies excluding Surgutneftegaz and Rosneft (right y-axis)
(Source: A.5 and the company homepages)
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8.3
State-owned companies
Before the fall, almost all of Russian oil production was controlled by the state. Today, there
is only one major company left: Rosneft.
8.3.1 Rosneft
Rosneft is used by the Russian state as a mean to regulate the domestic fuel- and energy
sectors (A.4). Rosneft has been growing lately, partly by buying assets from Yukos. It claims
to have proved oil and gas reserves of over 20 Gb of oil equivalents (about 16 Gb of oil),
which would make it the âworld leader among public oil companiesâ (B.37).
8.3.2 Transneft
Transneft was formed in 1993 and is the legal successor of the USSR Ministry of Oil Industry
Main Production Department for Oil Transportation and Supplies (Glavtransneft). As the
name suggests, Transneft is not an oil producing company. Rather it is responsible for
maintaining the already existing vast pipeline network in Russia (Figure 16), planning and
building new pipelines and also for the management of the oil transfer through the pipelines.
Transneft transports 93% of the oil produced in Russia. (B.34)
8.4
Independents
An so-called âIndependentâ is usually a small-sized private oil company that is very common
in market-based oil industries. They mostly do not have the resources to develop new basins
or start to develop larger fields. Instead they take over larger oil fields as they have passed
their peak, and manage the decline phase in a more economic way than a large oil company
could do. They also discover the medium and small oil fields, which are often found after the
larger ones. This means that the independents are important in keeping up the production after
the large fields start to decline and thus slow down the decline rate of mature basins. (A.5 p.
143)
In Russia, where the state controlled the oil production until 1991 and then mostly large oil
companies emerged, the whole idea of small and independent companies did seem strange,
and the climate for such companies was not very inviting. However, Russian companies
wanted western technology to improve production and started getting into joint ventures with
western companies.
There are Russian Independents, but they are not that common. However, two large
Independents in the Volga-Ural region â Tatneft and Bashneft â are noteworthy. They have
been producing the Romashkino and Federovskoye fields respectively from the beginning.
During the nineties they were seen as major oil companies. They do have refining facilities,
but are regionally rooted and have not evolved into any kind of international companies
making large acquisitions and so on. They can therefore be seen more as large Independents
(A.5 p. 147)
8.5
Future plans of Russia
Not too many new giant oil fields have been discovered lately. Lukoil claims having made the
largest oil discovery in Russia for 20 years: the Filanovskogo field with estimated recoverable
reserves of 1.6 Gb (B.18). But this is still a small field compared to Samotlor (27 Gb) or
Part two â Russia
41 (100)
Romashkino (17 Gb). Besides, at the current Russian production rate, 1.6 Gb would only
cover six months of production.
8.5.1 Oil production
Dr Iskander Diyashew, chief engineer of former Sibneft, expects Russia to be capable of
increasing its oil production to 12 Mb/d (an increase of 2.5 Mb/d) over the next 7 to 10 years.
(B.9).
With Lukoilâs planned 1 Mb/d increase (section 8.2.1) and assuming that the other oil
companies also increase their production, this might very well be a real possibility.
8.5.2 Pipelines
With the current growth in oil production, the export capacity might become the limiting
factor for production in the near future.
Currently, Russia has at least two major pipeline projects that are planned or in construction.
Figure 16. Main oil and gas pipelines in Russia. Source: B.35)
East Siberia â Pacific Ocean (ESPO) pipeline
The new Eastern Siberia Pacific Ocean pipeline (Figure 16, orange line) is supposed to
transport oil to China. It is built in two stages, whereof the first will extend the existing
pipeline from Kimeltey near the Baikal Sea to Skovorodino close to the Chinese border. This
stage is planned to be ready in 2008 and carry 30 million tonnes per year â equivalent to 0.6
Mb/d or six times the current Swedish import.
(B.38)
Bulgaria â Greece
A 280 km pipeline from Burgas in Bulgaria to Alexandroupolis in Greece (Figure 17) has
been approved for and is to be ready in 2010. It is designed to transfer between 35 and 50
million tonnes yearly, or about 0.7-1 Mb/d. (B.39) One reason for building the pipeline is to
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bypass the shipping bottleneck in Bosporous, but it is believed that Russiaâs real motive is to
bypass Turkey completely in order to gain more control over the oil transports. (B.25)
Figure 17. The planned Burgas-Alexandroupolis pipeline. The dashed lines are
simplified shipping routes. Source map for routes: B.25
Added together, these two new pipelines can transfer 1.3-1.6 Mb/d. Does Russia expect to be
able to increase its exports by the same amount for a period of 20-30 years â the payback time
for building pipelines? Or is the goal simply to re-route current oil exports from more
expensive transportation types to pipeline? Probably it is a combination of both. Even though
Russia wouldnât be able to fill the pipelines, the new export options will make it possible to
route the oil to the countries that generate the highest profit.
Part two â Russia
43 (100)
9
How much oil is left in Russia?
To estimate the remaining recoverable reserves is not an easy task, especially concerning a
country like Russia from where it is hard to get reliable data. Production data is the most
reliable data since the oil flow can easily be measured at the production plants. To estimate
how much oil is left is another matter. It is impossible to know for sure how much an oil field
holds. Also, the original estimates from the petroleum engineers might become exaggerated
later on in order to encourage investments in the field. (C.3)
9.1
Classification of oil fields
Not only is this kind of information hard to find because of the secretive nature of Russia, but
also because reserves in oil fields are not classified in the same way in Russia as in most other
countries.
In a large part of the world, different estimates of the amount of oil left is measured according
to a de facto standard set by the Society of Petroleum Engineers (SPE). This standard has
been renewed in March 2007, but since older data sources are used in the thesis the older
1997 standard is used. SPE defines reserves as âthose quantities of petroleum that are
anticipated to be
commercially
recovered from known accumulations from a given date
forwardâ. Below is a simplified reserve classification (source: B.26):
Proved reserves
Proved reserves refer to the amount of oil that exists in known fields and is
commercially recoverable at a reasonable from a given date forward.
Unproved reserves
Unproved reserves are based on geologic and/or engineering data similar to that
used in estimates of proved reserves, but they canât be classified as
proved
due
to technical, contractual, economic, or regulatory uncertainties. Unproved
reserves can be divided into
probable
and
possible
reserves:
Probable reserves
Probable reserves are those unproved reserves that are more likely
than not to be recovered.
Possible reserves
Possible reserves are those unproved reserves that are less likely to
be recoverable than probable reserves.
These reserve estimates can be thought of as distinct amounts of oil. As an example, proved
reserves can be 10 Gb, probable reserves 6 GB and Possible reserves 6 GB. These amounts
can then be summed together to get three commonly-used estimates of the amount of
recoverable oil from the field (Table 1). Each estimate is also coupled with a pre-defined
probability of finding that amount of oil.
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Table 1. Commonly used oil reserve estimate definitions
Abbreviation
Means
Probability of finding at least
the specified amount
1P
Proved
90% (P90)
2P
Proved + Probable
50% (P50)
3P
Proved + Probable + Possible
10% (P10)
Russia uses a different system. The oil reserve estimates are expressed by the letters A, B, C1,
C2, D1 and D2, where A is most probable. The Russians themselves classify their oil in the
following manner:
Proved reserves
A â geologically examined reserves currently in production
B â geologically examined reserves, which are the unused production capacity
C1 â geologically evaluated reserves, which according to engineering data show
partial recoverability
Probable reserves
C2 â reserves that are presumed to exist, based on geological and geophysical
data analogous to that of verified reserves
D1 â speculative reserves, presumed to exist on basis of geological analogy to
reference areas
D2 â same as D1, but less evaluated
(B.16)
The Russian definition of âprovedâ reserves is not the same as the SPE:s âprovedâ. The main
difference is that the Russian definition looks at what is geologically possible to extract but
does not take into consideration the economical factors. This means that Russian reserve
numbers given with the Russian system tend to be about 20-30% larger than the similar SPE
number.
Part two â Russia
45 (100)
9.2
Reserve estimates
There are many estimates of how much oil Russia has left. A collection of different estimates
was found in an article from the Oil Drum website written in 2006 (B.7):
Table 2. Estimates for Russian oil reserves. Unit: Gb. The red, yellow and green colours
are use later on for distinguishing between the different scenarios. Source: B.7
Source
Reserves [Gb] (method used)
Oil & Gas Journal
60 (proven SPE)
John Grace
68 (proven SPE)
World Oil
69 (proven SPE)
British Petroleum
72 (proven SPE)
10 largest Russian Oil Companies
82 (ABC1)
E Khartukov (Russian Oil Expert)
110 (ABC1)
United States Geological Survey
116 (proven SPE)
Ray Leonard (MOL)
119 (ABC1)
Wood Mackenzie
120 (proven SPE)
IHS Energy
120 (ABC1)
M. Khodorkovsky (former Yukos)
150 (he's in jail)
Brunswick UBS (consultants)
180 (proven, P50, P5 SPE)
DeGolyer & MacNaughton (audit)
150 to 200 (proven SPE?)*
* a value of 175 Gb is used for the mean value calculation in Table 3.
Because these estimates differ quite a lot, it would not be very meaningful to use just one
single estimate or the mean value of all estimates. In the original Oil Drum article, the oil
reserve estimates are divided into two groups: a âlow campâ who believe that thereâs less than
100 Gb left and a âhigh campâ who believes that there is more. However, it might be
interesting to study a middle case as well. In this thesis the estimates are divided into three
groups (shown as red, yellow and green in Table 2). A mean value is calculated for each
group and is rounded to the closest 10 Gb (Table 3). These mean values are then used in the
Hubbert curve in chapter 11 and the Depletion rate model in chapter 12.
Table 3. Calculation of oil reserve estimates for Russia
Mean (calculated) [Gb]
Mean (rounded) [Gb]
Low estimate, 60-100 Gb
70.2
70
Middle estimate, 101-140 Gb
117.0
120
High estimate, 141-200 Gb
168.3
170
Many of the estimates in Table 2 are quoted to be pure âprovedâ reserves without any
probable, possible or yet-to-find oil. However, these âprovedâ values vary too much (60 - 200
Gb) to consider them all to be reliable âprovedâ estimates. The vast majority is 120 GB or
lower. Therefore the estimates are interpreted in a slightly different way when used in this
thesis. The 70-120-170 Gb values are seen as estimates of
recoverable reserves
plus
yet-to-
find
oil for the 2006-2050 time period, or in other words URR minus the Cumulative
Production in year 2006.
The 70 Gb estimate
is used as a âworst-caseâ estimate. Since even the most pessimistic
source (Oil & Gas Journal) gives Russia 60 Gb of proved reserves, and that number doesnât
include any probable/possible/yet-to-find reserves, it can be concluded that whatever happens,
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Russia will have at least 70 Gb of oil left â it can not get worse than this unless all the other
estimates are completely wrong.
The 120 Gb estimate
is considered to be either a very optimistic proved reserve estimate or a
slightly optimistic proved estimate together with some yet-to-find oil.
The 170 Gb estimate
is considered to be very optimistic. It is assumed that any yet-to-find
oil that is found during the studied time period (2006-2050) is economically viable to
produce. It should cover the claims of most optimists.
9.3
A word on Arctic oil
The United States Geological Survey (USGS) have been claimed writing in their USGS
World Petroleum Assessment 2000 report that the Arctic would hold 25% of the worldâs
remaining resources (B.8). Since a large part of the Arctic belongs to Russia (Figure 18), this
would mean that Russia is sitting on large potential oil resources and that even the 170 Gb
âoil leftâ estimate discussed in 9.2 could be too small.
Figure 18. The Arctic region. Source: WoodMackenzie
(http://www.woodmacresearch.com/content/portal/energy/arctic/arcticbrochure.pdf)
A recent report from Wood Mackenzie hints that the Arctic might have much less potential oil
resources than earlier estimated. In key basins, the amount of oil is believed to be only one-
fourth of some earlier estimates. The report also states that 85% of the already discovered
resources and 75% of the future exploration potential is believed to be gas (B.12). The report
still gives the South Kara Yamal basin nearly 90 Gb of yet-to-find oil. This number sounds
very high, and it should be remembered that even if it would be true, Arctic oil is more
expensive, more difficult and slower to produce than a land-based field. The report estimates
Part two â Russia
47 (100)
that the expected
worldwide
peak of oil production from the Arctic will be about 3 Mb/d and
occur in 20 years (B.8). Since Russia only holds part of the Arctic oil in the world, the
Russian peak would be less than 3 Mb/d.
If current Russian hydrocarbon reserves can be seen as a hint, the âlot of gasâ statement seems
to be true. Russia, with more than 25% of the world reserves (B.4), has the worldâs largest
natural gas reserves. Most of the currently producing fields and the (already found) remaining
reserves are situated in the Arctic region.
Why is it then often claimed to be unlikely to find oil in the Arctic while there may be large
amounts of gas? One possible reason is presented below.
Oil is formed when dead organic matter gets buried and gets under pressure at a specific
temperature interval of about 50-150 °C. Since temperature increases with depth, the oil can
only be formed in a specific depth interval of about 2-6 km
9
called the
oil window
(Figure 19).
At depths below 6 km it is much more likely to find gas than oil. (A.12)
Figure 19. The Oil Window. The relation between depth and temperature is based on a
geothermal gradient of 2.6°/100m, which is global average. Source: A.10 p. 20 fig. 3.1
The Arctic region has been subject to vertical movement of the crust due to the alternating
weight of the ice cap in the past. Source rock that originally was inside the oil window might
have been pushed downward so that gas has been created instead. (C.3).
9
This depth interval varies depending on the geothermal gradient. For the interval of 2-6 km a geothermal
gradient of 2.6°C / km is used.
Part three â Modelling
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10
Scenarios and input data
10.1
Description of the scenarios
Three different scenarios are going to be studied. For each scenario the three different oil
reserve estimates from chapter 9.2 are used. In other words, it is assumed that Russia has 70,
120 or 170 Gb of oil left.
1.
Constant production (at current production level)
How long will the oil last if todayâs production level of about 9.5 Gb/d (in 2006, B.23)
is held constant until the depletion rate sets the limit? In this scenario the exported
amount will decrease slightly over time due to the increasing domestic oil usage.
2.
Constant export (at current export level)
In the near future, the oil consumption of the countries that import oil from Russia can
be assumed to be at least constant. How long would Russia be able to maintain a
constant export to not make the situation worse for the importing countries? A
constant export would require an increasing production due to an increasing domestic
oil demand in Russia. Also, assuming that the mean oil price stays fairly constant, a
constant export would give Russia fairly constant export revenues.
3.
Increased export (initial +2Mb/d increase, then constant export)
This scenario assumes that Russia increases itâs oil export to a level that is 2 Mb/d
higher than today. Chapter 8.5.1 mentions a possible 2.5 Mb/d increase, so a 2 Mb/d
increase should be seen as technically possible. An extra 2 Mb/d would be more than
sufficient for the planned pipeline projects and also give some room for other export
possibilities. Considering the predicted increasing oil demand in nearby countries such
as China, Russia would have no problems finding customers.
Another reason for having a scenario with increased export is that Saudi Arabia, the
worldâs largest oil exporter, has been considering something similar. The stateâs own
oil company Saudi Aramco has made some scenarios for future sustainable oil
production (B.3). In one of these scenarios the Saudi oil production increases from 10
to 12 Mb/d during a four-year period. Since the Saudi domestic demand is very low
compared to their production, it is safe to assume that these extra 2 Mb/d will be
exported.
Since most of the Russian fields are small compared to the giant fields in Saudi
Arabia, Russia is given twice the time â 8 years or 2007-2014 â to ramp up their
export in this scenario. After 2014 the export will be flat until the maximum depletion
rate is reached.
10.2
Division of Russia into two main regions
The main goal of the thesis is to study Russia as whole. However, as shown in Figure 10 and
discussed in chapter 7, Russia is clearly dominated by Western Siberia and Volga-Ural.
It is interesting to study Western Siberia separately for a number of reasons. Oil production
started late compared to the other regions, which means that there are still considerable
Part three â Modelling
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amounts of oil left. The huge drop in production after the fall of the Soviet Union mainly
affected Western Siberia. The other regions â most importantly Volga-Ural and its
Romashkino field â had peaked a few decades earlier. Their production was declining
naturally and wasnât much affected by the fall of Soviet. The production fall of Western
Siberia, however, occurred mostly due to political reasons. If the decline had been natural, the
increased production of Western Siberia since the late 90âs (see chapter 7.2) would probably
not have been possible.
Volga-Ural is the second-largest region, and one would think that it also should be studied
separately. But considering that the production from the other regions is almost negligible,
those low-producing regions are added to Volga-Ural and the resulting region is called âRest
of Russiaâ.
In summary it is interesting to study Russia from two perspectives:
1.
Russia as a single unit
2.
Russia divided into two regions:
o
Western Siberia
o
Rest of Russia (Volga-Ural + other regions)
10.3
Time periods
During the Soviet time, there was almost no official data for Russian oil production and
reserves. After the fall of the Soviet Union, more and more data has become available, but
still, Russia is more secretive about its reserves and production than most other countries in
the world.
The scenarios can be divided into three time periods with different sets of data:
-
Late 1800-1948. Not much data available, but the cumulative production during this
period is negligible compared to todayâs production volumes.
-
1949-2002. Production data available.
-
2003-2006. Some production data available, but requires assumptions.
-
2007-2030. Purely forecast â the aim of this thesis. Only assumptions. Domestic oil
demand predictions from IEA/World Energy Outlook 2006 are available until 2030.
-
2030-2050. Purely forecast. Uses domestic oil demand predictions made in this work.
10.4
Production data and cumulative production
To estimate the production between 1870 and 1948, the production data in Table 4 is used.
For the years of which production data is not known, production is assumed to change linearly
between the closest known years. The production is thus assumed to be like in Figure 9.
This linear model gives that the cumulative production until 1949 is about 6.4 Gb, which is
rounded upwards to 7 Gb. Even though the error in this estimate might be large percentage-
wise, it doesnât matter much in the long run. Russia currently produces about 9.5 Mb/d or 3.5
Gb/year. The whole cumulative production of 7 Gb would therefore last only two years.
Aram MĂ€kivierikko
52 (100)
Table 4. Production data used for estimating cumulative oil production until 1948.
Figure 9 in chapter 6.1 is made using this data.
Year
Source
[Mb/y]
[b/d]
1870
0,24
660 Grace
1875
1,1
3000 Grace
1885
14
39000 Grace
1898-1901
91 250000 Grace: half of 500 000 brl/d world production
was split between Russia and USA between
1898-1901
1913
75 206000 Grace
1918-1921
30
81000 Grace: average output between 1918-1921
1928
91 250000 Grace: "...not until 1928 did Russia regain
1901:s output".
1939
227 622000 Grace: Oil productionâŠreached 622000 brl/d by
the Second World War
1941
238
Tiratsoo
1945
167
Tiratsoo, not sure of year
1946-1948
167
Assumed to continue at 1945 level.
Main source: Grace, John D, 2005, Russian Oil Supply (p 7-10)
Oil production
The yearly production data for total Russia and the Volga-Ural region during the years 1949-
2002 is read from Figure 10. The Western Siberia production data is then calculated by
subtracting the Volga-Ural from the Total production for each year.
Total oil production in 2006 is assumed to be 9.5 Mb/d according to World Energy Outlook
2006 (A.6). Production for 2003 and 2004 is then calculated as a linear function between 2002
and 2005.
How the total production 2003-2005 is split between Western Siberia and Rest of Russia is
not known. The following assumptions are made:
Rest of Russia is quite mature, and will continue with the same year 2002 production as year
2002 during 2003-2005. The rest of the required production will then come from Western
Siberia.
10.5
Oil left in 2006
As discussed in chapter 9.2, a low (70 Gb), medium (120 Gb) and high (170 Gb) estimate for
the amount of oil left to produce is used in this study. These estimates are then split so that
68% is assumed to come from Western Siberia and 32% from the Rest of Russia (B.11).
These values are assumed to be valid for year 2006; as the time goes on, more oil is pumped
up and less oil is left in the ground.
10.6
Depletion rate
For a definition of depletion rate, see chapter 1.2.3. The depletion rate is dependent on the
amount of oil that is left. The three estimates of 70, 120 and 170 Gb of oil left year 2005 will
affect depletion rates considerably. It can be helpful to study the depletion rate to see what
kinds of oil reserves are reasonable. If, for instance, the scenario with 70 Gb of oil would give
a very high depletion rate of 10-20%, one could conclude that the amount of oil that is left
must be more than 70 Gb, because such a high depletion rate is unreasonable.
The question is, then: what is a reasonable depletion rate?
Part three â Modelling
53 (100)
Before discussing the
depletion
rate, one thing about the
decline
rate should be noted. The
model in chapter 12 is constructed in a way that makes the decline rate equal to the depletion
rate
during the decline phase
(see Appendix C 17.1.1). Because of this, decline rate and
depletion rate are used interchangeably in the discussion below.
A normal decline rate for a
single
giant oil field is somewhere around 6-16% (A.10 p. 118). A
country
that consists of many fields of different sizes that are taken into production at
different times has a much lower depletion rate. Table 5 shows the depletion rates for
different regions and countries in the world calculated by Campbell (C.3).
Table 5. Examples of depletion rates. Source: C.3
World
2,60%
Regions
Countries
Europe
6,7%
Norway
7,2%
N.America
5,0%
UK
6,5%
ME Minor
4,7%
US-48
4,5%
L.America
4,5%
Russia
3,6%
East
3,9%
Eurasia
3,0%
Africa
2,9%
ME Gulf
1,7%
In general, high tech offshore areas have a depletion rate around 6-8% (C.3). This is because
offshore equipment like oil rigs are expensive to build and maintain; the companies want to
get back their invested money as soon as possible and thus the oil is produced at a quick rate.
Norway is an example of an offshore country, and as expected it has a fairly high depletion
rate of 7.2%.
For lower-tech regions/countries where the production is mainly onshore (US, Russia...) a
depletion rate of 3-5% can be expected. (Campbell, mail conversation, 2007-04-13)
The OPEC countries (Middle East, among others) have an even lower depletion rate because
the production is constrained artificially, not because of natural limits. The Middle East
countries have realized the importance of a âsustainableâ oil production â they will try to
maintain a quite constant production as long as possible instead of producing as fast as
possible (B.3).
In Table 5 Campbell estimates the current Russian depletion rate to 3.6%. It is important to
remember that this rate is based on a specific âoil left to produceâ estimate. For example, the
historical production data in Figure 10 together with the reserve estimates in chapter 9.2 give
current (year 2006) depletion rate estimates of 5.53% (70 Gb oil left), 3.23% (120 Gb oil left)
and 2.28% (170 Gb oil left). Even if the âoil leftâ estimates used would be good ones, new
technology could help increasing the production rate. The following excerpt is from a forum
post at the oil drum: (B.28)
Matthew Simmons claims that the 3% rate comes from the depletion data of
U.S. oil fields. But the U.S. oil fields were the first. They were exploited with
old technology, which drained reservoirs slowly. They also benefited from new
technology, which fattened the tail end of the production curves.
Aram MĂ€kivierikko
54 (100)
He says a lot of new fields today are exploited using high-tech methods from the
beginning. Many oil industry experts assume that means total recovery will be
greater. Simmons says that's wrong. You may get the oil out faster, but total
recovery will be the same or worse. Which means the backside of the curve will
be much steeper for these modern oil fields than they were for the old U.S. ones.
Many oil fields in Russia are quite old, and in the 90âs there was a lack of investments to hold
the fields modern. However, during the recent few years, investment and new technology has
become more and more common, so a maximum rate of about 4-5% might be reasonable in
the not too distant future.
Since the maximum depletion rate is an important parameter for the model described in
chapter 12, it is of interest to test a few different values of the depletion rate. In this thesis
three maximum depletion rate values are used:
3%, 4.5%
and
6%
. These rates are selected so
that they would give an as large range as possible without being unrealistic.
The 3% maximum rate could be seen as a kind of worst-case, which will probably not occur
unless Russia faces some sort of a major crisis like a huge economic depression with ignored
maintenance of the fields, a large-scale sabotage of the oil fields or a third world war.
The 4.5% maximum rate is a middle alternative, a little bit on the optimistic side but certainly
doable. If world oil prices continue to increase like they have done recently, Russia will
probably want to earn as much as possible while they still have enough oil left to play with,
and therefore keep up a fairly high depletion rate.
The 6% maximum rate can be seen as very high considering that Russia is not a offshore
country. Still, with lots of new technology and major investments it is not a totally unrealistic
figure.
It should be remembered that the amount of oil that can be produced is still the same
regardless of the depletion rate. A high maximum depletion rate delays the point in time when
the production becomes restricted and thus allows a constant/growing production to be held
for a longer time. This is preferable for the countries that import oil from Russia. The
downside: when the production starts falling, it falls fast. A low depletion rate means that the
production starts to decline early, but can continue at a low rate for a longer time.
10.7
Domestic oil demand
It is important to estimate the domestic usage of oil, since it plays an important role in
calculating the oil export. Oil that is produced but not used domestically can be exported:
Oil export = Oil production â Domestic oil usage
10.7.1 Historical domestic oil demand
Let us study some historical data for the oil usage of Russia by looking at Figure 20.
According to BP statistical Review (lower solid line) the domestic usage was quite flat at
about 5 Mb/d until the fall of the Soviet Union in the 1991. During the next 5 years the
consumption almost halved to about 2.6 Mb/d and then was flat for a few years. Since 2001
Part three â Modelling
55 (100)
the consumption has been slowly rising again, but not at all as fast as the oil production
(upper solid line).
Another estimate made by Grace (lower dashed line) (A.5 p 68) shows a much higher
domestic consumption during the Soviet time, even when taking into account Graceâs slightly
higher production estimate (upper dashed line). Even though Graceâs estimated consumption
gets closer to BPâs numbers after the fall of Soviet in 1991, Graceâs estimate is still about
50% higher in 2000. If Graceâs estimate were closer to the truth, the 2006 amount of exported
oil would be about 1.5 Mb lower than what is used in this thesis. This would make the export
stop (chapter 13.2.2) to occur earlier than estimated.
Figure 20. Russian oil production vs oil consumption 1985-2005: IHS(prod)-BP(cons)
vs. Grace (prod&cons). (Source for consumption data: B.4 and A.5 p. 68)
10.7.2 Future oil demand prediction by IEA
As an aid in determining a reasonable future domestic oil usage, World Energy Outlook 2006
is used.
WEO â Reference scenario
In the reference scenario the
average estimated yearly growth of oil demand for Russia is 1%
during the period 2005-2030. This is quite low compared to the world average of 1.3% or the
developing countries average of 2.5%, but is still higher than 0.6% in the industrialized
countries (Europe, Northern America, Pacific).
However, WEO also expects the growth to happen in two steps. During 2004-2015 it will be
1.4%. They also express the estimates in Mtoe
10
and use a conversion factor of 1 Mtoe =
0.0209 Mb/d
2004 â 130 Mtoe = 2.72 Mb/d
10
Million Tons of Oil Equivalent
Aram MĂ€kivierikko
56 (100)
2015 â 152 Mtoe = 3.18 Mb/d (yearly demand growth 2004-2015: 1,4 %)
2030 â 170 Mtoe = 3.55 Mb/d (yearly demand growth 2004-2030: 1,0 %)
WEO â Alternative policy scenario
The alternative policy scenario is based on a much faster reduction of hydrocarbon usage in
the world, which according to the report is only possible if the todayâs politicians take some
quite drastic measures. A 0.5% growth in oil demand is assumed for Russia during 2004-
2030, or 0.7% during 2004-2015. The estimated actual production numbers are
2004 â 130 Mtoe = 2.72 Mb/d
2015 â 140 Mtoe = 2.93 Mb/d (yearly demand growth 2004-2015: 0,7 %)
2030 â 149 Mtoe = 3.11 Mb/d (yearly demand growth 2004-2030: 0,5 %)
10.7.3 Oil demand predictions used in the model
The World Energy Outlook scenarios described above will be used in the model with some
modifications. The oil demand in the model is assumed to reach the 2015 and 2030 amounts
predicted by WEO 2006. However, the yearly demand growth rates used by World Energy
Outlook are based on a consumption of 2.5 Mb/d in 2004. The model used in the thesis starts
in 2006 with a higher domestic consumption. The scenarios used in the model will therefore
get yearly growth rates that differ slightly from WEO 2006.
Estimated domestic oil demand in 2006
The 2006 oil demand is determined by multiplying the 2005 demand of 2.753 Mb/d with the
1.4% growth rate between 2004-2005 (Source data: B.4)
Demand 2006 = 2.75*1.014 = 2.7915
â
2.79 Mb/d
Reference policy used in model
The demand growth 2030-2050 is assumed to stay at a yearly rate of 0.736%. This
assumption is made to keep the âbusiness as usualâ spirit of the WEO reference scenario even
though WEO only covers the years 2004-2030.
- Start year: 2006 (oil demand 2.79 Mb/d)
- Yearly demand growth 2006-2015: 1.464 % (oil demand 3.18 Mb/d in 2015)
- Yearly demand growth 2016-2030: 0.736 % (oil demand 3.55 Mb/d in 2030)
- Yearly demand growth 2031-2050: 0.736 % (oil demand 4.11 Mb/d in 2050)
For calculations of the demand growths, see Appendix C 17.2.
Alternative policy used in model
It should be noted that the Alternative Scenario in World Energy Outlook is already quite
optimistic regarding its estimated growth rate of only 0,7% until 2015 when taking into
account that the current growth rate is about 1,4 % (B.4). To really get a âbest-caseâ
alternative policy that clearly differs from the reference scenario, the demand growth during
2030-2050 is assumed to be 0% due to even further energy efficiency measures and higher
domestic oil prices.
- Start year: 2006 (oil demand 2.79 Mb/d)
- Yearly demand growth 2006-2015: 0.545 % (oil demand 2,93 Mb/d in 2015)
Part three â Modelling
57 (100)
- Yearly demand growth 2016-2030: 0.398 % (oil demand 3.11 Mb/d in 2030)
- Yearly demand growth 2031-2050: 0 % (oil demand 3.11 Mb/d in 2050)
For calculations of the demand growths, see Appendix C 17.2.
In Figure 21 the oil demand growth for the reference and alternative policy used in the model
are compared with the static 2004-2030 growth rates of 1% and 0,5% that are suggested by
World Energy Outlook. When extrapolating these growth rates from 2030 to 2050, it can be
seen that the scenarios used in the model are still more optimistic than the ones suggested by
World Energy Outlook.
Figure 21. Domestic demand comparison. Reference and alternative policy demand vs.
constant 0.5% and 1% growth rate.
Aram MĂ€kivierikko
58 (100)
11
The Hubbert Model â a first estimate
Before diving in to the main model of the thesis â the Depletion rate mode in chapter 12 â a
study based on the less complicated Hubbert model is made. It is interesting to compare the
production limits given by the both models.
11.1
Theory
For an ideal oil field that is not affected by political or economical decisions, the production
curve versus time looks something like Figure 22 a).
When production starts, the oil pressure in the field is the highest. The oil production is
mostly limited by the production capacity of the wells. The best spots to place wells are found
and taken into production first. The production rises exponentially to a start. After a while, it
becomes increasingly hard to find good new places where to drill. Production is still going
strong from the old wells. The production often levels out at a plateau for a few years
depending on the field size. As the oil level is dropping, so does the pressure. Experience
shows that when about 50% of the oil in the field has been pumped away, the production
starts to decline. A phase of a kind of artificial breathing begins with methods such as
-
Water injection. Water is inserted from the bottom of the field. The water sweeps the
oil upwards towards the wells. The oil then becomes increasingly mixed with water.
-
Gas injection, for example natural gas (mainly methane CH
4
), N
2
(nitrogen) or CO
2
(carbon dioxide), keeps the pressure high. CO
2
injection has the advantage of making
the oil flow better through the rock.
-
Artificial fracture of the reservoir. If the oil field is âtightâ, i.e. consists of dense
limestone, the reservoir can be fractured to make the oil flow more easily. Can be
combined with sand injection into the cracks to open them up even more.
When using these technologies it is important to not empty the field too fast, but to use them
to produce the oil in an optimal way. This has not always been the case in Russia, especially
not during the eighties when the peak production should be kept at any price (A.5).
Finally, when the production from the field gets below a certain limit, it is not longer
economical to continue production. The production is stopped even though the field is not
totally empty.
Figure 22. a) Typical oil production profile for a single field. b) Comparison between a
Hubbert curve and a normal distribution, both with the same area and peak.
Part three â Modelling
59 (100)
Figure 22 a) approximates the production from a single oilfield. But what about the
production for a region with many fields, or a country as a whole?
In March 1956 the American geophysicist M. King Hubbert (1903-1989) presented a paper
for the American Petroleum Institute. He had created a model which given a URR would
predict the peak for a country. Hubbert predicted that the USA
11
would peak âin 10-15 yearsâ
or 1965-1970. The peak occurred in 1970. He also applied the model for the worldwide oil
and natural gas production and believed in a peak âa half decade laterâ â around 2006. (B.24)
When adding together production from many fields, the result can be approximated with a
Hubbert curve (Formula 3). The Hubbert curve looks a lot like a bell-shaped normal
distribution curve, but has a slightly narrower peak and a wider base as shown in Figure 22 b)
!
P
(
t
)
=
aU
2
+
2cosh(
a
(
t
"
t
m
))
Formula 3. The Hubbert curve, where
P(t) = production as time t
t = time (year); the value on the x axis in the graph
t
m
= year of production peak
U = Ultimately Recoverable Reserves (URR)
a = slope factor
For a region where oil production is limited only by natural constraints, the Hubbert curve can
work quite well. But as soon as other factors such as political decisions come into play it is
hard to draw any accurate results from such an approach. In the case of Russia, such a factor
would be the fall of the Soviet Union, which had severe impact on the whole country. If the
Hubbert model is used without any kind of âreality checkâ the results can be unrealistic, as we
shall see.
The Hubbert model is used below to calculate two things:
1.
An estimate how much oil Russia has left â it is interesting to compare this with the
oil left estimates from chapter 9.2.
2.
Peak year, peak production and production stop estimates by using the oil left
estimates of 70, 120 and 170 Gb from chapter 9.2.
11.2
Oil left estimate (variable URR)
One easy but not-so-accurate way of estimating the amount of oil left is to look at a graph of
historical oil production and try to fit a Hubbert curve over the historical production. This is
done in Figure 23. The area below the historical production curve is a close approximation
12
of the cumulative production, which is about 140 Gb
13
in 2006. In the figure there is also four
Hubbert curves (Curve 1-4), of which curve 2-4 can be disregarded for now.
11
More strictly, Hubbert was speaking about âL48â â the lower 48 states, excluding Hawaii and Alaska
12
The area only takes into consideration the oil produced during 1950-2006. The cumulative production from
late 1800 until 1949 is so small that it does not matter in this simple model.
13
My estimate based on historical production data and production estimates for 2003-2006
Aram MĂ€kivierikko
60 (100)
Curve 1 (dashed) shows the Hubbert curve that best fits the growing phase 1955-1980 of the
Russian production. The growing phase was used because the production during that time
period was not disturbed in any way. The fit was made using the least-squares method and the
constraints described in Appendix B 16.1. The curve would imply that Russia has 39 Gb of oil
left in 2006. The URR would then be 140 + 39 = 179 Gb. However, with a current production
of 3.5 Gb per year
14
the current depletion rate would be 3.5/39 = 9.0%. That is unrealistically
high for a country with mostly land-based production as discussed in chapter 10.6.
If it is instead assumed that the peak and decline occurred earlier than the natural limits would
have forced them to, a Hubbert curve with a later and higher peak â and thus a larger URR â
could be a better choice. However, studying curves 2-4 (results of chapter 11.3 below) shows
that as the estimated URR increases, the curves start differing so much from the actual
production that it very hard to know which URR would be âcorrectâ.
Figure 23. Hubbert curves applied to Russian oil production. Includes estimates of
domestic usage
11.3
Production estimates
Assumed that Russia has 70, 120 or 170 Gb of oil left as discussed in chapter 9.2 â how
would the future production look like, and how large would the peak production be? When
adding these oil left estimates to the cumulative production of 140 Gb in 2006, three URR
estimates are obtained: 210, 260 or 310 Gb. Using the same method and constraints as in the
last subchapter, curves (2)-(4) in Figure 23 were obtained. Since the curves differ so much
from the actual historical production during 1980-2006, it is impossible to draw any correct
conclusions about the future production.
11.4
Production estimates â delayed Hubbert curve
Fitting a Hubbert curve to the first growth phase in Russian oil production didnât work. If the
curve is instead fitted to the currently occurring second growth phase 1999-2006 using the
14
9.5 million barrels per day in 2006 equals 9.5*365/1000
â
3.5 billion barrels per year
Part three â Modelling
61 (100)
constraints in Appendix B 16.2, curves (2)-(4) and the accompanying data in Figure 24 are
obtained.
Figure 24. Delayed Hubbert curves applied to the Russian oil production. The area
under curve 2, 3 and 4
from year 2006 and forward (the vertical grey line)
is 70, 120 or
170 Gb respectively. The later export year in each range is a result of the lower domestic
oil demand in the alternative policy.
The delayed peak approach gives seemingly better production estimates. The 70 and possibly
the 120 Gb case might occur in the future. The 170 Gb case, however, seems to be too
extreme; even if Russia would be technically able to increase its production to a 13.6 Gb
peak, it would not make much sense to do so. If the domestic demand would behave as
predicted, any increase in production would need to be exported. Great investments would be
needed to build up an improved export infrastructure with pipelines, harbour terminals and
railroads. This infrastructure would only be used at its full capacity during a short time period.
The payback time for the investments would become very long. Also, if the oil price
continues to rise, significantly larger export profits could be obtained in the future. Lastly, the
importing countries would face great problems if they would grow accustomed to huge
exports from Russia but suddenly those exports would start dropping.
The conclusion is that another kind of model must be used to
-
get a more reasonable oil production and export estimate without the high and sharp
peaks given by the Hubbert model
-
study the three scenarios described in chapter 10.1.
This in done in the next chapter.
Aram MĂ€kivierikko
62 (100)
12
The Depletion Rate Model
To be able to study the scenarios in chapter 10.1, a model has been developed. The model is
based on the idea that the oil production of a country is limited by a maximum depletion rate
â thus I have decided to call it âThe Depletion Rate Modelâ. The idea of making a model
based on the depletion rate comes from Colin Campbell.
Below a motivation for the Depletion Rate Model is given, followed by a detailed description
of parameters and the calculation methods.
12.1
Why use depletion rate?
To make an exact model of how an oil field will behave is not an easy task. The oil producing
companies have people whose sole job is to take into consideration many different parameters
such as the type of source rock, the rockâs permeability, field pressure, (more) and try to make
an estimate of how much oil is in the field, how much can be produced, and how the future
production will look like. That kind of modelling requires quite some knowledge, and is
different from field to field. In spite of individual differences, most fields will have a rising,
peak and decline phase. Adding many fields together â from a region, a country or even for
the world â will show a pattern somewhat similar to the normal distribution curve in chapter
11.
Russia has had a very clear rising phase (-1980), a peak phase (1985-1988) and a kind of
âfalseâ decline phase (1989-1995), plateau production (1996-1999) and is again (2000-)
increasing its production. In the future there will inevitably come a ârealâ decline phase that is
naturally constrained. How should it be modelled?
One way to model the decline in production is to use a constant decline rate. The production
next year then becomes a percentage of the production last year, and we get an exponential
decay. There are some problems with using the decline rate, however.
- It does not take into account the amount of oil left, but only the variations in production of
two subsequent years. Separate calculations would be needed for deciding when the
production should become limited by the decline rate in order to not make the model produce
more oil than is available.
- When looking at historical data, the decline rate is very fluctuating from year to year. It is
hard to draw conclusions for long-term rates.
If instead depletion rate is used, these two problems are solved.
- The depletion rate is defined as the current yearâs production divided by the oil that was left
at the start of the year. Since less oil is left each year, the depletion rate slowly increases
during the rising and peak phase of a normal production profile. By limiting the production
when a maximum depletion rate is reached (see example in Figure 25), the natural constraints
are taken into consideration and the model will avoid an unrealistically fast exploitation of the
remaining available resources.
Part three â Modelling
63 (100)
Figure 25. Basics of the depletion rate model. The estimated future production starts to
decline (here in 2018) when the maximum depletion rate (here 4.5%) is reached.
- The depletion rate is much more stable over time unless the amount of oil left is very small.
This can be seen in Figure 26, which compares the decline rate with the depletion rate (120
Gb oil left in 2006 is assumed) using the historical production data. The decline rate fluctuates
heavily between years and in the case of Russia ranges from -30% in 1955 (not seen on graph)
to almost 14% in 1998. It is hard to make any long-term predictions from it. The depletion
rate on the other hand is much more stable â it rises slowly, and varies between approximately
0 to 3%.
The dip in the depletion rate that occurs after the fall of the Soviet Union in 1991 is unusual
and is an indication of the premature decline phase discussed in chapter 6.4. A naturally
constrained decline with a fairly constant depletion rate would have implied that Russia would
have even less oil left than in the most pessimistic estimate in Table 2. The current large
production increase would also be impossible.
Figure 26. Depletion rate compared to decline rate (both on the left Y axis) using
historical production data (right Y axis). The depletion rate (blue/circle) fluctuates much
less than the decline rate (red/triangle).
Aram MĂ€kivierikko
64 (100)
12.2
Input parameters
The upper part of Table 6 shows an example of how the input looks like inside the Excel
model. The most important input parameters are described briefly later in this subchapter. A
more complete description is given in Appendix C 17.3.
Table 6. Input and output parameters for the model (example from Scenario 2).
Strikethrough numbers are not used for calculations in this particular model setup.
Input parameters
Scenario number
2
Mode*
2
* Mode 1: Prod change factor determines production
Mode 2: Export determines production
Start year
2006
Domestic oil comsumption (ref) 2006
[Mb/d]
2.79
Domestic oil comsumption (alt) 2006
[Mb/d]
2.79
Domestic usage change factor (ref)
1.0146
Domestic usage change factor (alt)
1.0055
Russia (total)
Western Siberia
Rest of Russia
Oil left 2006
[Gb]
70
120
170
48
82
116
22
38
54
URR
[Gb]
210
260
310
115
149
183
92
108
124
Production limitation parameters
Max depletion rate (yearly)
[%]
4.5%
4.5%
4.5%
4.5%
4.5%
4.5%
4.5%
4.5%
4.5%
Depletion rate decrease (max, yearly)
[%]
0.15%
0.15% 0.15%
0.15%
0.15% 0.15% 0.15% 0.15% 0.15%
Production change factor (max, yearly)
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
Export change factor (yearly)
1.000
1.000
1.000
Start year parameters
Production 2006
[Mb/d]
9.50
9.50
9.50
7.23
7.23
7.23
2.27
2.27
2.27
Cumulative Production 2006
[Gb]
139.50
139.50 139.50
67.27
67.27
67.27
69.71
69.71
69.71
Depletion rate 2006
[%]
4.72% 2.81% 2.00% 5.53% 3.23% 2.28% 3.57% 2.12% 1.50%
Decline rate 2006 (no impact on model)
[%]
-3.26%
-3.26% -3.26%
-4.33%
-4.33% -4.33%
0.00%
0.00% 0.00%
Output parameters
Russia (total)
Western Siberia
Rest of Russia
Oil left
Oil left 2030
[Gb]
23
44
83
16
26
48
8
18
34
Oil left 2050
[Gb]
9
18
33
6
10
15
3
7
18
Oil left 2030
[%]
11%
17%
27%
14%
17%
26%
8%
17%
28%
Oil left 2050
[%]
4%
7%
11%
5%
7%
8%
3%
7%
14%
Production
Cumulative production 2030
[Gb]
186
215
227
99
123
134
84
90
90
Cumulative production 2050
[Gb]
200
242
276
109
139
168
89
101
106
Peak
[year]
2006
2018
2030
2006
2018
2030
2011
2031
2051
Max production
[Mb/d]
9.5
10.0
10.3
7.2
7.7
8.0
2.3
2.3
2.3
Mean production
[Mb/d]
3.9
6.4
8.6
2.7
4.5
6.3
1.2
1.9
2.3
Min production
[Mb/d]
1.2
2.3
4.3
0.8
1.3
2.0
0.4
1.0
2.3
Depletion rate
Max depl. rate
[%]
4.7%
4.5%
4.5%
5.5%
5.4%
6.0%
4.5%
4.5%
4.4%
Mean depl. rate
[%]
4.5%
4.2%
3.6%
4.6%
4.6%
4.5%
4.4%
3.6%
2.5%
Min depl. rate
[%]
4.5%
2.8%
2.0%
4.5%
3.2%
2.3%
3.6%
2.1%
1.5%
Decline rate
Max decline rate
[%]
7.7%
4.5%
4.5%
10.2%
7.5%
9.2%
4.5%
4.5%
0.0%
Mean decline rate
[%]
4.4%
3.0%
1.7%
4.7%
3.5%
2.7%
3.8%
1.9%
0.0%
Min decine rate
[%]
-3.3%
-3.3%
-3.3%
-4.3%
-4.3%
-4.3%
0.0%
0.0%
0.0%
Export
Export stop (ref. scenario)
[year]
2026
2038
2051
Max export (ref. scenario)
[Mb/d]
6.7
6.7
6.7
Mean export (ref. scenario)
[Mb/d]
0.4
2.9
5.1
Min export (ref. scenario)
[Mb/d]
-2.9
-1.8
0.2
Export stop (alt. scenario)
[year]
2029
2043
2056
Max export (alt. scenario)
[Mb/d]
6.7
7.0
7.1
Mean export (alt. scenario)
[Mb/d]
0.9
3.4
5.5
Min export (alt. scenario)
[Mb/d]
-1.9
-0.8
1.1
Import
Import need (ref) 2030
[Gb]
0.4
0.0
0.0
Import need (ref) 2050
[Gb]
14.5
4.2
0.0
Import need (alt) 2030
[Gb]
0.0
0.0
0.0
Import need (alt) 2050
[Gb]
8.8
1.2
0.0
Part three â Modelling
65 (100)
12.2.1 Maximum depletion rate
The maximal depletion rate is one of the most important parameters in the model. It sets the
limit on how much oil can be produced a specific year based on a specific URR.
Example (corresponds to Figure 25 in chapter 12.1)
-
Max depletion rate = 4.5%,
-
Depletion rate in year 2006 = 2.81%,
The depletion rate in year 2006 (2.81%) is smaller than the maximum allowed depletion rate
(4.5%). The production is not yet limited and can therefore be constant or keep growing.
Since the amount of oil left becomes smaller, the depletion rate will slowly increase. When
the depletion rate has reached the maximum allowed 4.5%, the production becomes
determined by the maximum depletion rate and thus starts to decline. The depletion rate is
never allowed to get higher than this maximal value unless it is already higher in year 2006
when the simulation starts (see chapter 12.2.2).
The higher the maximum depletion rate, the longer the production is allowed to grow (or be
constant), which in turn delays the peak. On the other hand the drop in the post-peak
production will be even steeper when the depletion rate limit is reached. Because the
maximum depletion rate has a considerable impact on the model results, three different
maximum depletion rates are used as discussed in chapter 10.6: 3%, 4.5% and 6%.
12.2.2 Maximum depletion rate decrease
If the depletion rate is higher than the maximal depletion rate at the start of the simulation, the
model puts a limitation on how fast the depletion rate can decrease. Currently it is set to 0.15
percentage units, which gives a smooth decline in production that looks reasonable compared
to the instant drop if not having any limitation at all or the quick decrease when using 0,5
percentage units (Figure 27).
Figure 27. Impact of the Maximum depletion rate decrease (MDRD) parameter on
production (Western Siberia, 70 Gb oil left, 3% maximum depletion rate)
Aram MĂ€kivierikko
66 (100)
Example (not related to the above figure):
-
Max depletion rate = 6%,
-
Depletion rate in year 2006 = 6.4%,
-
Max depletion rate decrease = 0.15 percentage units.
The depletion rate can drop by at most 0.15 percentage units. Thus the production for year
2007 is calculated in a way that the depletion rate for 2007 becomes 6.4 - 0.15 = 6.25%. Year
2008 the depletion rate is allowed to drop to 6.25 - 0.15 = 6.10%. Not until year 2009 has the
depletion rate dropped to its maximum allowed value of 6%.
12.2.3 Domestic Usage Change Factor
The
domestic usage change factor (DUCF)
is the estimated yearly change in the Russian
domestic oil demand. If the factor is 1, the oil demand is constant during the simulation
period. If it is larger than 1, the oil demand grows each year.
Two different DUCF values can be given as input parameters to the model.
If the model is set to
mode 1
(The
mode
parameter is discussed below in 12.2.8) it outputs two
different time series of export possibilities. These different time series are called the
reference
policy
and the
alternative policy
, a naming convention taken from IEA:s report
World Energy
Outlook 2006
(see chapter 10.7.2)
DUCF for the Reference policy
As discussed in 10.7.3, the following DUCF values are used for the reference policy:
2007-2015: 1.01464 (1.464 %)
2016-2050: 1.00736 (0.736 %)
DUCF for the Alternative policy
As discussed in 10.710.7.3, the following DUCF values are used for the alternative policy:
2007-2015: 1.00545 (0.545 %)
2016-2030: 1.00398 (0.398 %)
2031-2050: 1,0 (0 %)
The large number of decimals in the DUCF values above are needed to make the domestic
usage follow the World Energy Outlook estimates as close as possible.
12.2.4 Oil left 2006
As discussed in 9.2, three different estimates are used: 70, 120 and 170 Gb.
Western Siberia is estimated to hold 68% of the remaining oil (B.11). This means that Rest of
Russia holds the remaining 32%.
12.2.5 Ultimately Recoverable Reserves (URR)
By adding the three estimated Oil left 2006 values to the cumulative oil production 2006
(
â
140 Gb), three different estimates of Ultimately Recoverable Reserves (210, 260 and 310
Gb) can be calculated. The URR is used mainly in the calculation of the depletion rate.
Part three â Modelling
67 (100)
12.2.6 Production change factor
Scenario 1 is based on a constant production. The model thus needs some means to control the
production, and the production change factor accomplishes that:
Production this year = production last year * production change factor
If the factor is 1 (which is used for Scenario 1), the production is constant. If it is larger than
1, production increases.
12.2.7 Export change factor
Scenario 2 is based on a constant export, and scenario 3 is based on an increasing export. The
yearly change in export is controlled by the export change factor:
Export this year = export last year * export change factor
If the factor is 1, the export is constant. If it is larger than 1, export increases. The export
change factor values used in the model are discussed in Appendix C 17.3.2.
Aram MĂ€kivierikko
68 (100)
12.2.8 Mode
Two types of scenarios are studied. Scenario 1 is based on
production
, while scenario 2 and 3
are based on
export
. The model can thus be set up into different
modes
that correspond to
these scenario types. Each mode changes the way of calculating yearly production for the
three parts of the model:
Russia (total)
,
Western Siberia
and
Rest of Russia
.
Mode 1 â separate producing regions:
Production is individually determined for
Western Siberia
and
Rest of Russia
. The total
Russian production is the sum of these regions (Figure 28 a). Each region has its own
depletion rate that is always less than or equal to the maximum allowed depletion rate
(Figure 28 b).
a)
b)
Figure 28. Example of a) production and b) depletion rate when the model is set to mode
1. Maximum depletion rate is 4.5%.
Part three â Modelling
69 (100)
Mode 2 â export determines production:
In mode 2 Russian export is set as an input parameter. The model then calculates the required
oil production for Russia (total).
Since it is assumed that Rest of Russia canât give any significant oil production increase in the
future, Rest of Russia is set to not exceed the maximum depletion rate. Western Siberia is set
to produce the difference between Russia (total) and Rest of Russia. This means that Western
Siberia might experience higher maximum depletion rates than what is allowed for the
country as whole. This can be seen in Figure 29 b), where Western Siberia reaches almost
5,5% before slowly dropping back to the imposed level of 4,5%. This behaviour means that
the Mode 2 scenarios will be able to keep an unconstrained production for slightly longer than
Mode 1 scenarios.
a)
b)
Figure 29. Example of a) production and b) depletion rate when the model is set to mode
2. Maximum depletion rate is 4.5%.
Aram MĂ€kivierikko
70 (100)
12.3
Calculation
The calculation of the different parameters used in the model can be studied in greater detail
in Appendix C 17.4.
12.3.1 Yearly production
Most of the decision-making occurs in calculating the yearly production. This is described in
a simplified way below. A more detailed description is available in Appendix C 17.4.3.
The yearly production is determined according to the following (somewhat simplified) steps:
1.
Check if
last yearâs depletion rate > (max depletion rate + max depletion rate decrease)
(this condition can only occur in the beginning of the simulation).
If yes, reduce production so that the depletion rate is decreased by maximum depletion
rate decrease like in the example in chapter 12.2.2. If no, go to step 2.
2.
Check if
last yearâs depletion rate > max depletion rate
Also check if
this yearâs depletion rate at current production rate > max depletion rate
(this condition is true during the decline phase)
If yes to any of the two checks above, produce an amount of oil that makes
this yearâs depletion rate = max depletion rate
.
If no, go to step 3.
3.
Lastly, if production is not limited by the maximum depletion rate, let the scenario
continue to calculate production (i.e. constant or increasing production).
12.4
Output parameters
The model outputs two types of information:
1. Yearly estimates 2007-2050 of
- production [Mb/d]
- cumulative production [Gb]
- depletion rate [%]
- decline rate [%]
- export (reference scenario) [Mb/d]
- export (alternative scenario) [Mb/d]
Since these yearly estimates depend on how much oil is left in Russia in the start of the
simulation period (year 2006), three different sets of yearly estimates are calculated â one for
each âoil leftâ estimate (70, 120 and 170 Gb, see 9.2). These estimates are calculated from a
start year with known data.
2. Key information that can be obtained by studying the yearly estimates
.
An example of Excel output parameters can be seen in the lower part of Table 6. Most of the
output parameters are self-explanatory. Some of them need a little bit more explaining.
Part three â Modelling
71 (100)
Peak
is the year when the production peaks. The peak year for Russia (total) is mostly the
same as for Western Siberia, since most of the production comes from Western Siberia.
Min/mean decline rate
can become negative if there is an increase in production during the
studied period.
Export stop
is the last year Russia can export oil according to the model. After this year,
Russian oil production will be smaller than its domestic consumption. Russia will have to
start to import oil.
The model stops at year 2050. If the export has not stopped by then, the stop year is calculated
by extrapolating the change in export (Export
2049
âExport
2050
) linearly into the future to see
when the export reaches zero. Export stop years later than 2050 are thus less accurate than
those occurring between 2006-2050.
Min/mean export
can become negative if there is an import need during the studied period.
Import need (year)
gives the cumulative import need from the
year after the export stops
until the
specified year
(2030 or 2050). It shows how much Russia would have to import
provided that the domestic demand follows the predictions in chapter 10.7.3.
Considering that
- the world oil production might peak at latest in 2018 (A.10)
- the results in the next chapter show that the export stop year generally occurs much later
than 2018, Russia might find it difficult to import any oil from the time of the export stop
year. When the export stop year occurs there will likely be great competition over the
remaining oil. The remaining oil exporting countries would probably not be able to increase
their production to fulfil Russiaâs domestic oil demand. Even if Russia would manage to start
importing some of the existing oil production, the market price of oil would probably be so
high that it would not make any economic sense for Russia to try to compensate the
decreasing domestic production for any longer time period.
One way to model this situation in an assumedly more realistic way would be to force the
domestic oil usage to follow the production after the export stop year. No imports would then
be needed.
Aram MĂ€kivierikko
72 (100)
13
Depletion Model Results
13.1
Reference policy
All scenarios were simulated. The results are presented in a series of figures.
Figure 30 shows the production that would occur in the different scenarios if the domestic
demand were to follow the reference policy. The figure is mainly for illustration purposes to
see how different the results can be depending on the input data, but one conclusion can be
made: the Russian production will have dropped to 5 Mb/d or less in year 2050.
To better study the different outcomes, they are divided
i) by scenario (Figure 31)
ii) by the 70-120-170 Gb oil left estimates (Figure 32).
13.1.1 Figure notation â an explanation
The legend in the figures are notated in the following way:
âScenario - oil left year 2006 â maximum depletion rateâ. For example, âS1-70-3.0%â refers
to Scenario 1, a 70 Gb of oil left estimate in 2006 and a maximum depletion rate of 3.0%.
In Figure 31 and Figure 32, symbols and colours are used in a consistent way:
Both figures: triangles = 6%, circles = 4.5% and squares = 3% depletion rate.
Figure 31: red = 70 Gb, yellow = 120 Gb, green = 170 GB oil left estimate
Figure 32: red = Scenario 1 (constant production), yellow = Scenario 2 (constant export),
green = Scenario 3 (increased export)
Figure 30. Oil production history and production estimates for all scenarios (1-3), all
reserve estimates (70, 120, 170 Gb) using the reference policy for domestic demand
Part three â Modelling
73 (100)
a)
b)
c)
Figure 31. Production estimate for the reference policy. a) Scenario 1, b) Scenario 2, c)
Scenario 3
Aram MĂ€kivierikko
74 (100)
a)
b)
c)
Figure 32. Production for the a) 70 Gb, b) 120 Gb and c) 170 Gb oil left estimate
Part three â Modelling
75 (100)
13.2
Alternative policy
13.2.1 Production
First note that since scenario 1 is based on a constant production, the difference in domestic
usage for the reference and alternative policies only affects the export. Therefore the
production for the alternative policy is the same as for the reference policy in Figure 31 a).
Now letâs take a closer look at the export-based scenarios 2 and 3. As long as the production
is not limited by the maximum depletion rate, the alternative policy has the following effect:
Smaller domestic usage --> less production (compared to the reference policy) is needed to
maintain a constant/rising export --> the depletion reaches its maximum value later in time -->
the production peak is delayed.
Figure 33 compares the reference policy production to the alternative policy production for
scenarios 2 and 3. Since it takes some time before there is any significant difference in the
reference/alternative domestic oil demand, only the production scenarios that peak relatively
late are studied in the figures. The figures show that the delayed peak effect is almost non-
existing in most cases. The largest difference â a two-year delay â is seen in the 170 Gb / 6%
cases, but it is insignificant in the long run.
a)
b)
Figure 33. Production peak comparison, reference vs. alternative policy for a) Scenario
2, b) Scenario 3. An âaâ after the scenario number (i.e. S3
a
) stands for âalternative
policyâ. Observe that the x-axis in b) starts and ends 5 years earlier than in a).
Aram MĂ€kivierikko
76 (100)
The main interest of this thesis is to see how long Russia can hold a constant (or increasing)
production â in other words to estimate out when the production will peak. Since the
difference in the peak year between the reference policy and the alternative policy is
insignificant, it can be concluded that it is not necessary to study the alternative scenario in
detail â a study of the reference scenario is sufficient.
13.2.2 Export stop
The âexport stop yearâ is the only parameter that is somewhat affected by the alternative
policy. This is because the export stop occur much later than the peak; the difference in
domestic demand between the reference and the alternative policy has grown fairly large.
Figure 34 compares the minimum, mean and maximum export stop years for the reference
and alternative policy for the different scenarios and for the 70-120-170 Gb oil left cases.
In the âby scenarioâ comparison, scenario 1 shows the largest difference. The mean export
stop year is delayed 5 years and the maximum is moved 10 years into the future.
In the âoil leftâ-comparison, the 120 Gb case sees a delay of the mean by 5 years. The 170 Gb
case has an even large delay of 8 years.
Figure 34. Comparison of max/min/mean values of the export stop year for the
reference and alternative policy domestic oil usage. Left: by scenario. Right: by oil left
estimate. Note that export stop year that occur later than 2050 are not very accurately
calculated, see chapter 12.4.
Part three â Modelling
77 (100)
13.3
Minimum, mean and maximum values
In addition to studying the specific scenarios, it is interesting to study different minimum,
mean and maximum values of the different output parameters described in chapter 12.4.
Table 7 shows the min/mean/max values of all the output parameters grouped by the 70-120-
170 Gb oil left estimates.
Table 7. Minimum, mean and maximum values of output parameters from the model.
The min/mean/max values are calculated both for all scenarios and the 70, 120 and 170
Gb cases separately
Output parameters
All scenarios
70 Gbrl scenarios
120 Gbrl scenarios
170 Gbrl scenarios
MIN
MEAN
MAX
MIN
MEAN
MAX
MIN
MEAN
MAX
MIN
MEAN
MAX
Oil left
Oil left 2030
16
51
93
16
23
31
34
47
59
68
83
93
Oil left 2050
5
22
51
5
10
17
10
20
32
20
36
51
Oil left 2030
7,8%
18,7%
30,0%
7,8%
11,1%
14,6%
13,2%
18,2%
22,7%
22,3%
26,9%
30,0%
Oil left 2050
2,2%
8,1%
16,5%
2,2%
4,8%
8,0%
3,8%
7,8%
12,4%
6,5%
11,7%
16,5%
Production
Cumulative production 2030
176
207
238
176
185
193
198
211
222
217
226
238
Cumulative production 2050
190
236
286
190
198
205
225
238
248
258
272
286
Peak
2006
2016
2036
2006
2007
2010
2006
2014
2023
2014
2026
2036
Max production
9,5
10,1
12,2
9,5
9,6
10,3
9,5
10,2
12,0
9,5
10,6
12,2
Mean production
3,5
6,2
9,4
3,5
3,9
4,2
5,6
6,3
6,9
7,5
8,4
9,4
Min production
0,8
2,6
5,0
0,8
1,1
1,4
1,7
2,3
2,7
3,5
4,2
5,0
Depletion rate
Max depl. rate
3,00%
4,71%
6,00%
4,72%
5,21%
6,00%
3,00%
4,50%
6,00%
3,00%
4,40%
6,00%
Mean depl. rate
2,68%
4,07%
5,95%
3,24%
4,57%
5,95%
2,95%
4,13%
5,47%
2,68%
3,52%
4,70%
Min depl. rate
2,00%
2,98%
4,95%
3,00%
4,10%
4,95%
2,75%
2,83%
2,89%
2,00%
2,01%
2,04%
Decline rate
Max decline rate
3,00%
5,29%
7,93%
6,00%
7,04%
7,93%
3,00%
4,63%
6,00%
3,00%
4,21%
6,00%
Mean decline rate
1,33%
3,09%
5,21%
4,05%
4,58%
5,21%
2,67%
3,01%
3,59%
1,33%
1,69%
2,08%
Min decine rate
-3,26% -3,26% -3,26% -3,26% -3,26% -3,26% -3,26% -3,26% -3,26% -3,26% -3,26% -3,26%
Export
Export stop (ref. scenario)
2021
2038
2055
2021
2024
2027
2037
2039
2041
2047
2050
2055
Max export (ref. scenario)
6,7
7,1
8,7
6,7
6,8
7,4
6,7
7,1
8,7
6,7
7,4
8,7
Mean export (ref. scenario)
0,0
2,7
5,9
0,0
0,4
0,7
2,1
2,8
3,4
4,0
4,9
5,9
Min export (ref. scenario)
-3,3
-1,5
0,9
-3,3
-3,0
-2,7
-2,4
-1,8
-1,4
-0,7
0,1
0,9
Export stop (alt. scenario)
2021
2040
2061
2021
2025
2027
2038
2040
2042
2049
2054
2061
Max export (alt. scenario)
6,7
7,1
8,9
6,7
6,8
7,4
6,7
7,2
8,8
6,7
7,5
8,9
Mean export (alt. scenario)
0,2
2,9
6,1
0,2
0,6
0,9
2,3
3,0
3,6
4,2
5,1
6,1
Min export (alt. scenario)
-2,7
-1,0
1,4
-2,7
-2,4
-2,1
-1,8
-1,2
-0,8
-0,1
0,7
1,4
Import
Import need (ref) 2030
0,0
0,3
2,1
0,4
1,0
2,1
0,0
0,0
0,0
0,0
0,0
0,0
Import need (ref) 2050
0,0
6,7
17,2
14,5
15,9
17,2
3,1
4,2
6,5
0,0
0,1
0,4
Import need (alt) 2030
0,0
0,2
1,6
0,3
0,7
1,6
0,0
0,0
0,0
0,0
0,0
0,0
Import need (alt) 2050
0,0
5,3
14,6
11,9
13,2
14,6
1,5
2,6
4,7
0,0
0,0
0,0
Aram MĂ€kivierikko
78 (100)
a)
b)
Figure 35. Minimum, mean and maximum production for 70, 120 and 170 Gb oil left
estimates a) without and b) with historical production. The lines and bullets for the
mean series are extra large. Observe that the minimum/maximum production curves
simply take the minimum/maximum values from each subset (70-120-170 Gb) of the
simulations. This means that the âmaxâ curves show a production that might not be
possible in reality â it picks the best parts from all scenarios. This can be seen clearly in
the â170 maxâ (topmost) curve. It first follows the S3-170-6% case that starts declining
in 2030. In 2033, it switches to the S2-170-6% case, which peaks in 2036. And around
2046 it starts to follow yet another simulation that does not decline as fast as the S2-170-
6%.
Part three â Modelling
79 (100)
Figure 36. Mean export comparison between the reference policy and the alternative
policy for 70, 120 and 170 Gb oil left estimates.
13.4
Summary of peak and export stop years
The most interesting results are in my opinion the span of years when events such as
production peak or export stop will occur. These are shown in Figure 37, which for example
shows that Russia will peak between 2006-2036 and stop exporting 2021-2065. The peak year
data is taken directly from Table 7, and the export stop years are a combination of the data in
the same table.
Figure 37. Max, min and mean years for peak production (P) and export stop (E) for all
scenarios and 70/120/170 Gb estimates. The coloured lines show the results from the
delayed Hubbert model in chapter 11.4.
Aram MĂ€kivierikko
80 (100)
14
Discussion
14.1
Depletion Rate Model vs. Hubbert Curve
Even though there are difficulties applying the Hubbert (H) model to Russian production (see
chapter 11.4), the results obtained from it are quite similar to the Depletion Rate Model (D)
results in Figure 37 above. The early peak in the H-170 Gb case is expected due to the
unrealistically high peak production. The H-70 Gb peak occurs later than the D-70 mean
value because H production doesnât get limited early by a maximum depletion rate. The H-
120 Gb results are surprisingly close to the D-120 mean values. Regarding export stop years,
the H ranges are all inside the DR ranges. Conclusion: the Hubbert Curve â if used with
common sense â can be quite useful for simple modelling of the Russian oil production!
14.2
Model parameter impact on the results
Since the model is based on depletion rate, it can clearly be seen that the following two input
parameters are the ones that affect the outcome of the model most:
-
the estimated amount of oil left in 2006 (70, 120 or 170 Gb).
-
the maximum allowed depletion rate (3, 4.5 or 6 %)
If the amount of oil left and the maximum depletion rate are held constant, all scenarios
described in chapter 10.1 behave quite similarly. This is most clear in the 70 Gb case in
Figure 32 a). The production curves appear to be divided into groups according to their
maximum depletion rate. The group with 3 % depletion rate drops in production quite
drastically. The 4.5 % group drops in a more normal way. The 6 % group can actually keep on
producing until 2009-2010 until the decline kicks in. This same âgroupingâ can more or less
be seen in b) and c), but it is less pronounced.
14.3
How probable are the different outcomes from the scenarios?
References to the different scenarios or groups of scenarios are written in the notation
introduced in chapter 13.1.1.
14.3.1 70 Gb scenarios
Letâs study the 70-3% group in Figure 32 a) a bit closer. This group sees production fall of
almost 50% in only 9 years (2006-2015) with maximum
decline
rates (not depletion rates) of
between 6-7.9% depending on scenario. Historically (1949-2006) such a steep decline has
occurred during the following five-year period:
1990 â 6.7 %
1991 â 10.8 %
1992 â 13.8 %
1993 â 12.5 %
1994 â 9.4 %
However, the period occurs in the same timeframe as the fall of the Soviet Union. The steep
decline in production did not occur due to natural constraints but due to the insufficient
maintenance of the fields. I find it hard to believe that Russia would be constrained by a
maximum depletion rate as low as 3% any time soon unless the oil-production is slowed
down politically or hindered by other means. It is in the interest of the oil companies to keep
up the oil production and most importantly the profitable oil export. Conclusion: the 70-3%
group can likely be discarded.
Part three â Modelling
81 (100)
As of 2006, Russiaâs production is still increasing, even though the increase now seems to be
slowing down. The quick decline in the 70-4.5% group seems to force the production to turn
around a bit too quickly even when taking into account that a real peak would look smoother.
The 70-6% scenario looks reasonable in theory, but on the other hand a depletion rate of 6%
is quite high. Even though many old fields are enhanced with newer technology, Russia is a
large country with many fields. To reach a depletion rate of 6% within just a few years would
probably be almost impossible or at least require very large investments.
The conclusion about the 70 Gb scenarios is that either Russia is currently really pushing the
production at a depletion rate of more than 4.5 %. Or, what is more likely, they have more
than 70 Gb left.
14.3.2 120 Gb scenarios
Now letâs study figure Figure 32 b). If Russia is assumed to have 120 Gb of oil left, the
scenarios are allowed to develop a bit more â except for the 120-3% ones, which start to
decline immediately (S1) or almost immediately (S2 â 2008, S3 â 2009).
The observant reader might have noticed the following peculiarity:
-
The 4.5% production-based (mode 1) scenario 1 starts its decline in 2015.
-
The 4.5% export-based (mode 2) scenario 2 has a higher production, but still starts its
decline three years
later
.
The difference between mode 1 and mode 2 (chapter 12.2.8) explains this. Russia as a country
reaches the maximum depletion rate slightly later that Western Siberia. In scenario 1, the
production starts to drop as soon as Western Siberia reaches its maximum depletion rate. In
scenario 2 (and 3), the depletion rate for Western Siberia is higher (5.44% at S2 peak in 2018)
than the implied maximum rate (4.5%). Russia and can thus keep producing for an extra few
years. This same reasoning is true for the 6% cases.
Scenario 3 (increased export) doesnât look probable. At 4.5% depletion rate (S4-120-4.5%)
the production will not even reach the +2Mb/d goal before the decline starts. Even at a
depletion rate of 6% the increased export would only be maintainable for 5 years â a far too
short payback time for any pipeline investments. Russia seems to be certain having more than
120 Gb of oil left. If they donât, many of the current pipeline projects might become under-
utilized shortly.
14.3.3 170 Gb scenarios
Lastly, letâs look at Figure 32 c). For once the 3% scenarios survive a bit longer before they
peak. Even the aggressively growing S3 will just be able to reach the +2Mb goal before it
starts its decline.
The 4.5% case is far more promising. S1 peaks in 2028, S2 in 2030, and even if S3 peaks
already in 2024 its production still doesnât fall below the 2006 level of 9.5 Mb/d until 2030.
Any new pipelines would be useful for a long enough time.
If Russia can manage to reach a depletion rate of 6% â and as time goes on, that becomes
more probable since new technology increases production rate â they will not have any
Aram MĂ€kivierikko
82 (100)
problems with declining oil until 2029 when S3 peaks, and it falls below the 2006 production
in 2034. S1 and S2 peak in 2034 and 2036 respectively.
14.3.4 The mean values
Each separate production simulation has a very flat production and a very sharp peak. The
mean production scenarios in Figure 35 follow a smooth production and have smooth peaks.
They probably show a more realistic production profile. The min/max borders also show the
great uncertainty of the peak year.
14.4
Factors not taken into consideration in the model
The simple model that is used in this thesis can only give a hint about how much oil Russia
would be able to produce and export in the future, assumed that Russia has somewhere
between 70 and 170 Gb oil left to produce. The time profile of how much Russia will actually
produce and export depends on two major factors that canât be modelled in an easy way, since
they donât have anything to do with natural constraints:
-
The amount of investments made in oil producing and refining capacity
-
Strategic political decisions about how to use internal natural resources
These factors will be discussed below.
14.4.1 Investments
Investments are an important factor. That was shown very clearly during the fall of the Soviet
Union. The huge drop in oil production was not due to natural limits. It was due to neglected
maintenance of the oil fields, which in turn was due to the lack of investments. Before the fall,
most of the Russian oil companies were owned by the communistic state. After the fall the
companies are much more constrained by market forces and have also become independent
from the state. It should be in the interest of the companies to maintain sufficient investments
to keep up their oil production. It does not seem likely that a future decline would have lack of
investments as its main reason.
14.4.2 Political decisions
Russia is included in the top-ten (probably top-five depending on how much oil they actually
have left) countries with the largest proven recoverable oil resources and has by far the largest
natural gas resources in the world. This means that many countries in Europe and Asia are
interested in Russiaâs natural resources. Many of the former satellite states are in fact already
quite dependent on gas imports from Russia. How will Russia handle this situation?
In 1997, before becoming the Russian president, Vladimir Putin wrote a thesis about the
Russian energy policy, and also later in 1999 an article on the subject (B.2). In the article,
Putin seems to be very aware of the value of the Russian natural resources â especially the
hydrocarbon resources â and wants to use them for giving Russia the economic growth that
they need while still protecting the interests of the Russian state and people.
One key problem is the question of export vs. domestic usage. Here, Russia faces a problem
that can be traced back to the Soviet Union times. Energy used to be very cheap for the
Part three â Modelling
83 (100)
Russian consumers (including the satellite states) compared to the world market prices. This
meant that the consumers developed a wasteful attitude to their energy consumption that has
proven to be hard to change.
After the fall, the government controlled the oil price so that it would not skyrocket too fast.
In 1992, the oil price was $0.50/b compared to the world market price of more than $19/b.
The domestic oil price was increased quite drastically over the next few years, but it still
didnât reach anywhere near the market price â see Figure 38 (A.5). Therefore the oil export to
countries that pay the market price is an important source of revenue for Russia.
On the other hand, access to cheap energy is a key factor for any country that wants to build
up its economy and increase itâs GNP
15
.
Figure 38. Comparison between the domestic Russian oil price vs. the market price
(Source data: Domestic price 1992-1995: A.5. US Average oil price: B.15)
The question arises: what will happen in the future when the oil production starts to drop? The
export will probably follow the production curve for a while, just like in the model. But as the
increasing domestic demand approaches the decreasing production, decisions needs to be
made about the future. Should the production be kept at maximum possible levels to keep up
the export as long as possible, like in the model? Such an approach would fit the importing
countries while also generating revenues for the state and the involved companies.
An alternative, long-term strategy would be to greatly reduce the exports and thereby reduce
the production. Russia could keep being self-sufficient on energy considerably longer.
Renewable energy technologies would get sufficient time to develop and mature in order to
become viable alternatives for Russia.
14.4.3 A very large amount of Arctic oil
As discussed in chapter 9.3, Wood Mackenzie estimates that there could be up to 90 Gb of oil
in the Arctic. Any such large findings would probably be at least partly included in the
assumed âyet-to-findâ amounts of the 120 Gb and 170 Gb estimates discussed in chapter 9.2.
15
Gross National Product
Aram MĂ€kivierikko
84 (100)
But let us be very optimistic in the following example and assume that the Arctic oil would
not be included at all in the 70-120-170 Gb oil left estimates.
Let it be assumed that lots of Arctic oil is found in 2007. To be able to produce the oil,
production facilities and pipelines need to be built. A production start in 2015 is therefore
assumed. Further, Russia can be assumed to reach a production of 2 Mb/d of Arctic oil (2/3 of
the estimated 3 Mb/d world Arctic peak level) in 2026 (2026 was the peak year in the
WoodMackenzie article discussed in 9.3) and maintain it until 2050. Figure 39 shows this
Arctic production added to the mean values of the 70-120-170 Gb cases.
Figure 39. Arctic oil production estimate added to the mean value of the 70-120-170 Gb
scenarios
In the 70 Gb case, the arctic oil would make no difference in terms of peak production, but
merely partly compensate the decline of the other fields. It would create a production plateau
in 2015 when the Arctic oil production would start and also make it possible to maintain a
considerably larger production during the following decades. This would keep Russia self-
sufficient longer into the future, but the exports would still suffer.
In the 120 Gb case, the current production rate could be held for 4-5 more years and a
considerable production decrease would be delayed for 8-9 years.
The 170 Gb case is the one that would most visibly benefit from the Arctic oil. The peak
would be delayed 10-12 years, and a 1.3 Mb/d higher peak production would be achieved.
Not until 2037 would the production drop below 2006 levels.
It should be noted that this is an optimistic forecast. Arctic oil must be found before it can be
produced, and to date the vast majority of hydrocarbons in the arctic is gas. Also, the Arctic
fields are situated in very harsh production environments. To be able to produce oil, a large
pipeline infrastructure that can transfer such large amounts as 2 Mb/d must be built. Such
undertakings are expensive and take time. In reality the Arctic oil will probably start
contributing later than 2015. That would then mean that it would have an even smaller effect
on the peak production â but it would still help Russia to keep a somewhat higher production
level for a longer time.
Part three â Modelling
85 (100)
14.5
Short summary of results
Russia will peak somewhere between 2006 and 2036. If Russia has 70 Gb of oil left, the
production will peak 2010 at latest. However, they probably have somewhat more than that
(14.3.1). If it can be assumed that Russia has 120 Gb of oil left (the middle case), they can
keep up with the technology and they donât try to massively increase their production, the
peak can be assumed to occur around about 2015-2020. (13.4, Figure 37)
A massive production increase â and at the same time a large export increase (scenario 3) can
not be maintained for very long unless Russia has 170 Gb of easily producible oil left (Figure
31 c). The large infrastructure investments that would be needed could only be used at
maximum capacity for a few years before the peak would occur, and also it is not likely that
Russia has 170 Gb of oil left. Therefore it is unlikely that Russia will increase their production
by more than about 4-8% over todayâs level.
If Russia has 120 Gb oil left, the model predicts that Russiaâs will stop its oil export around
2040 (Figure 37). At this time Russia will likely be one of the last oil producing countries left
and wonât be able to import oil for their domestic needs (12.4). In reality the export stop will
probably happen sooner because Russia might realise that they need the oil themselves when
the production starts falling (14.4.2).
A heavily decreased domestic oil usage does not affect the production peak much (Figure 33).
Rather, it delays the export stop a few years (Figure 34).
A large finding of Arctic oil canât save the Russian production â it can in best case keep it up
10-12 years. (14.4.3)
14.6
Closing words and further study
Since the âoil leftâ estimates differ considerably for Russia, the possible range for the peak
becomes fairly wide. Still, this study shows with reasonable certainty the total span of
possibilities. Even if Russia in fact would have large amounts of oil left, they must be found
before they can be produced. Therefore the importing countries should be prepared for a
starting decline in production/export around 2015 (mean value of the 120 Gb oil left estimate)
and be happy if a high production can continue to be maintained after that.
One area of further study would be to make a more thorough study of all of the oil companies
and their future production plans and try to distinguish between how much is to be produced
through acquisitions of other companies and how much the existing production is going to be
changed. Also the pipeline plans could be studied more closely. What reserve and production
assumptions have led to planning and building the pipelines? Is the oil to be transported
supposed to come from an increased production, or does Russia simply want the possibility to
deliver oil to the countries that pay the most?
Appendices and References
Aram MĂ€kivierikko
88 (100)
15
Appendix A: Energy usage in Sweden
Note: most district heating in Sweden is mainly run on biofuels.
Figure 40. Energy supply in Sweden 1970-2005, excluding net energy export. Source
data: B.33
Figure 41. Final energy use in the residential and service sector, 1970-2005. Source data:
B.33
Appendices and References
89 (100)
Figure 42. Final energy use in the industry, 1970-2005. Source data: B.33
Figure 43. Final energy use in the transport sector, 1970-2005. Source data: B.33
Aram MĂ€kivierikko
90 (100)
16
Appendix B: Calculations for the Hubbert model
16.1
Oil left estimate
Curve 1 was created by letting the problem solver in Excel find the
a
,
t
m
and
URR
values that
minimizes the least-squares error between the curve and the historical production for year
1955-1980 with the following constraints:
- a
â„
0.07 (a minimum positive slope was given to help Excel. For 0 < a < 0.07 the curve -
became almost flat)
-
!
”
â„
1970 (peak year later than 1970; also there to help Excel)
- URR
â„
Cumulative production = 140 Gb
16.2
Production Estimates â delayed Hubbert curve
- The cumulative production starting from year 2007 and into the future (the model stops
counting in year 2100) must be close to the 70, 120 or 170 Gb oil left estimate.
- The best fit is made for the latest growth phase 1999-2006. The fit for curve 2 and 3 is done
by hand; the problem solver in Excel couldnât find a reasonable solution.
Appendices and References
91 (100)
17
Appendix C: more about the Depletion Rate Model
17.1
Connection between depletion rate and decline rate
17.1.1 A constant depletion rate gives a constant decline rate
The depletion rate model is constructed so that it lets the depletion rate grow to a certain
maximum. When that maximum is reached, the production becomes constrained by the
maximum depletion rate. This in turn means that the decline rate becomes equal to the
depletion rate after the first year. This is proven below. Table 8 shows a numerical example.
Symbols used:
n
year
d
start year of decline phase (a constant determined by the model)
i
an arbitrary year after the decline phase has started (i
â„
d)
P
n
Production at year n
L
n
= L
n-1
â P
n
The amount of oil left at the end of year n
L
d-1
The amount of oil left the year before decline starts (a known constant)
D
Maximum depletion rate (a given constant; 2.5, 4 or 6.5% is used in the model)
Dr
n
= (P
n-1
â P
n
) / P
n-1
Decline rate at year n
Assume that the maximum depletion rate D is reached at year
d
.
L
d-1
is known. From year
d
and forwards, the production will be constrained by the depletion rate so that only D % of the
amount of oil left is produced:
P
d+i
= L
d+i-1
* D
(i
â„
0)
(1)
When producing like in (1), the amount of oil left at end of year
d+i
is only dependent on D
and the amount of oil left the previous year:
L
d+i
= L
d+i-1
â P
d+i
= L
d+i-1
â L
d+i-1
* D = L
d+i-1
*(1-D)
(i
â„
0)
(2)
Calculating Dr
d+i
for i
â„
1
16
while using (1) and (2) gives:
!
Dr
d
+
i
=
P
d
+
i
"
1
"
P
d
+
i
P
d
+
i
"
1
=
(1)
L
d
+
i
"
2
D
"
L
d
+
i
"
1
D
L
d
+
i
"
2
D
=
(2)
L
d
+
i
"
2
D
"
L
d
+
i
"
2
(1
"
D)D
L
d
+
i
"
2
D
=
L
d
+
i
"
2
D(1
"
(1
"
D))
L
d
+
i
"
2
D
=
D
(3)
Formula (3) shows the result sought for: if the production is determined by a constant
depletion rate, the decline rate equals the depletion rate.
Table 8. Constant D gives constant Dr â numerical example. D = 10% from year 1 and
forward which gives that Dr = D from year 2 and forward. The production of 12 units
for year 0 is an arbitrary value in order to give an arbitrary decline rate for year 1.
Year
Oil left Depletion rate
0
Oil_left*depl.=
12.000 100.00
= (P
-1
-P)/P
-1
1
100*10% = 10.000
90.00
10.00%
16.67% = (12-10)/12
2
90*10% =
9.000
81.00
10.00%
10.00%
= (10-9)/10
3
81*10% =
8.100
72.90
10.00%
10.00%
= (9-8.1)/9
4
72.9*10% =
7.290
65.61
10.00%
10.00%
= (8.1-7.29)/8.1
Decline rate
Production
and so onâŠ
16
i = 0 gives Dr
d+i
= Dr
d
= (P
d-1
â P
d
) / P
d-1
which is arbitrary; it depends on P
d-1
which is arbitrary at year d-1
since the production does not yet follow equation (1).
Aram MĂ€kivierikko
92 (100)
17.1.2 A constant decline rate does not give a constant depletion rate
The opposite is not true â a constant decline rate does
not
give an equal, constant depletion
rate in general. There is one exception to this, and that is if the depletion starts when the
depletion rate is equal to the constant decline rate that is going to be used for the decline. This
is demonstrated in Figure 44.
a)
b)
c)
Figure 44. Production (right axis). Depletion rate and Decline rate (left axis). URR = 100
Gb. A decline in production (the blue curve starts falling) with a constant decline rate of
10% starts at different times: a) when depletion rate = 10% = decline rate, b) when
depletion rate < 10% and c) when depletion rate > 10%. A constant decline rate only
gives a constant depletion in case a) (both continue at 10%).
Appendices and References
93 (100)
17.2
Growth rates used for calculating the domestic demand
Formula 4 is used to calculate the growth rate for the domestic demand.
!
P
current
"
x
endYear
#
startYear
=
P
future
$
x
=
P
future
P
current
%
&
'
(
)
*
1/(
endYear
#
startYear
)
Formula 4. Calculation of a growth factor in production or export.
P
current
= production (or export) at start year
P
future
= production (or export) at end year
x = growth factor; (x-1)*100 gives the percentage
startYear, endYear = start and end year of the period to be studied
Table 9. Calculation of domestic demand growth rate; input parameters and results
Policy
startYear endYear
P
current
P
future
Growth rate
Reference
2006
2015
2.79
3.18
1.464 %
Reference
2015
2030
3.18
3.55
0.736 %
Alternative
2006
2015
2.79
2.93
0.545 %
Alternative
2015
2030
2.93
3.11
0.398 %
17.3
Further description of the input parameters used in the
depletion rate model
17.3.1 Year
Year
is the start year of the simulation (in this case 2006). Production, cumulative production,
depletion rate and the amount of oil left must be known for this year. The year is also used as
start year in the graphs.
17.3.2 Export change factor
Scenario 1
The export change factor is not used in scenario 1.
Scenario 2
The export is supposed to be constant, so the export change factor is set to 1 for the whole
period.
Scenario 3
The export change factors are calculated using Formula 4 and shown in Table 10. The export
amount for 2006 is calculated by taking the assumed production minus the assumed domestic
demand: 9.5 - 2.79 = 6.71 Mb/d.
Table 10. Export change factors for Scenario 3.
startYear endYear
P
current
P
future
Export change factor
2006
2014
6.71
6.71 + 2 = 8.71
1.0331
2015
2050
8.71
(constant)
1
Aram MĂ€kivierikko
94 (100)
17.3.3 Dom_mode, Exp_mode and Prod_mode (not visible in Table 6)
The way the Domestic oil usage, Export and Production is given to the model is decided by
the Dom_Mode, Exp_Mode and Prod_mode variables. These can be individually be set to a
value of 1, 2 or 3:
1 â a single domestic usage change factor, export change factor or production change factor is
used throughout the whole simulation period (2007-2050).
2 â a separate domestic usage change factor, export change factor or production change factor
is given for each year in the simulation.
3 â does not use change factors at all. Instead it is possible to directly (in Mb/d) specify a
amount of export, production or domestic oil demand for each year
17.4
Calculations done by the depletion rate model
This section will describe how the calculations in the model are done. The following notation
will be used:
URR = Ultimately Recoverable Reserves
CP = Cumulative Production
P = Production
P
max
= Production change factor (defined in chapter 12.2.6)
C = domestic consumption
C
r
= domestic consumption in reference scenario
C
a
= domestic consumption in alternative scenario
D = Depletion Rate
MaxD = Maximum Depletion Rate
MaxDdecr = Maximum Depletion Rate Decrease (defined in chapter 12.2.2)
Dc = Decline Rate
E = Export
E
r
= Export in reference scenario
E
a
= Export in alternative scenario
E
max
= Export change factor (defined in chapter 12.2.7)
The index
-1
means âlast yearâ. For example P
-1
= production last year
Appendices and References
95 (100)
17.4.1 Depletion rate and its relation to production
The depletion rate is defined as this yearâs production divided by the amount of oil left at the
start of the year. The amount of
oil left
in the beginning of this year can be expressed as the
URR minus the cumulative production at the end of the previous year. Since the URR is a
constant and the last yearâs cumulative production CP
-1
is always known at the beginning of
the current year that we want to study the depletion rate can also be seen as a function of
production P (Formula 5).
D = P/(oil left) = P/(URR â CP
-1
) =
D(
P
)
Formula 5. Depletion rate as a function of production
Solving for the production gives Formula 6:
P = D*(URR-CP
-1
) =
P(
D
)
Formula 6. Production as a function of depletion rate
This function concept is useful when making test calculations to see how a certain production
would affect the depletion rate or vice versa. It is used in the description of the production
calculation in chapter 17.4.3.
17.4.2 Export
Mode 1
The export is calculated by taking the production minus the domestic consumption:
E = P - C
Mode 2
The export is the determining factor. Just like in the case with depletion rate, the production
needed for a certain export can be tested for by solving for the production:
P = E + C
17.4.3 Production
To start the simulation, the production and depletion rate of the prior year is needed.
Mode 1
When the model is set to mode 1, production calculation is made for Western Siberia and Rest
of Russia. A simplified description is given in chapter 12.3.1. A more detailed description is
given below in pseudo-code.
-
Before each if/else clause there is a comment that tells what the clause does. The
comment starts with
/*
and ends with
*/
.
-
Code written in
bold style
means function notation. For example,
P(
D
-1
- MaxDdecr
)
refers to production as a function of depletion rate (Formula 6) and is calculated as
(D
-
1
- MaxDdecr)*(URR-CP
-1
)
.
Aram MĂ€kivierikko
96 (100)
/* ********************* STEP 1 **************************
if (
(last yearâs depletion rate is larger than the maximum depletion rate)
AND
(the required decrease in depletion rate to bring this yearâs depletion
rate back to the maximum allowed depletion rate would be larger than the
allowed depletion rate decrease) )
--> Produce an amount that makes the depletion rate equal to last yearâs
depletion rate minus the allowed depletion rate decrease
These both conditions can be checked by one single statement:
Condition 1: D
-1
> MaxD <--> D
-1
â MaxD > 0.
Condition 2: D
-1
â MaxD > MaxDdecr
Since MaxDdecr > 0, it is sufficient to check only for Condition 2.
*/
if(D
-1
â MaxD > MaxDdecr) {
P =
P(
D
-1
- MaxDdecr
)
}
/* ********************* STEP 2 **************************
else if (
(the depletion rate last year is larger than or equal to the allowed
depletion rate)
OR
(production using last yearâs production multiplied by the production
change factor would lead to a too large depletion rate) )
--> Produce an amount that makes the depletion rate the maximum allowed
depletion rate
*/
else if ( (D
-1
â„
MaxD) OR (
D(
P
-1
*P
max
)
> MaxD ) ) {
P =
P(
MaxD
)
}
/* ********************* STEP 3 **************************
else
--> this yearâs production equals last years production multiplied by the
production change factor
*/
else {
P = P
-1
*P
max
}
The production for Russia (total) is the sum of the production from Western Siberia and Rest
of Russia.
Mode 2
When the model is set to mode 2, production is calculated for Russia (total). The production is
calculated almost in the same way as for Mode 1, but with two changes:
Appendices and References
97 (100)
In STEP 2, when checking if the depletion rate is about to become too large, the production
doesnât depend on the previous yearâs production but of the export and the domestic
consumption. The second argument in the
else if
clause therefore changes from
D(
P
-1
*P
max
)
to
D(
E
-1
*E
max
+ C
)
:
else if ( (D
-1
â„
MaxD) OR (
D(
E
-1
*E
max
+ C
)
> MaxD ) ) {
P = P(MaxD)
}
In STEP 3, if the production is not limited by depletion rate: produce in a way that the
export
requirement is fulfilled.
/* Production = last yearâs export * export change factor + consumption */
else {
P = E
-1
*E
max
+ C
}
17.4.4 Cumulative production
Last yearâs cumulative production plus this yearâs production
CP = CP
-1
+ P
17.4.5 Decline rate
The negative relative change in percent compared to last yearâs production. Since the rate is
called
decline
rate, a
positive
decline rate means that the
production is declining
.
Dc = -(P/P
-1
- 1) = (1- P/P
-1
)
Aram MĂ€kivierikko
98 (100)
References
A. Printed sources
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99 (100)
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st
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(english: Energy
content of different fuels)
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Aram MĂ€kivierikko
100 (100)
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11-14
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Russia, Bulgaria, Greece signs major oil pipeline deal
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03-15
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C. Personal communications
1.
Aleklett, Kjell. Personal communication 2007-04
2.
Campbell, Colin. Personal communication 2006-09-16 â 2006-09-23
3.
Campbell, Colin. Mail communication 2007-04-13 and 2007-06-26
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Höök, Mikael,
Uppsala Hydrocarbon Depletion Group
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2007-04
5.
Leonard, Ray. Mail communication 2007-05-21
6.
Olsson, Rustan:
Preemraff
, Mail communication 2007-05-07