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GLOBOTEK HOLDINGS Inc. Information Memorandum 2010
GLOBOTEK HOLDINGS Inc.
Information Memorandum
2010
2009 i
Executive Summary ............................................................................................................................. 1
Background .......................................................................................................................................... 2 Business Proposal ............................................................................................................................ 3
Gas Flaring and Venting ...................................................................................................................... 5
Global Environmental Problem ....................................................................................................... 6 Focus on Russia ............................................................................................................................... 8 Focus on Kazakhstan ..................................................................................................................... 12 Focus on Turkmenistan .................................................................................................................. 13 Focus on Nigeria ............................................................................................................................ 13
Other Nations ................................................................................................................................. 14 Clean Development Mechanism .................................................................................................... 15
Technology Partner – Globotek ......................................................................................................... 15 Exclusive relationship .................................................. Ошибка! Закладка не определена.14
Overview of Globotek ................................................................................................................... 16
Manufacturing plant / facility in Tolyati ................................................................................... 18 Core Technology ........................................................................................................................... 19
Conventional technologies for associated petroleum gases ....................................................... 19
Globotek‘s technology for associated petroleum gas ................................................................ 22 Methanol Recovery .................................................................................................................... 23
Competitive advantages of these technologies .............................................................................. 24
Licensing and State Control ....................................................................................................... 24 Equipment Manufacture ............................................................................................................ 25 Stages of Design, Manufacture and Installation ........................................................................ 26
Manufacturing & Assembly Capabilities ...................................................................................... 28 Existing Installations ................................................................................................................. 28
Potential projects in Russia ............................................................................................................ 29 Globotek‘s Management ................................................................................................................ 30
Competitors ........................................................................................................................................ 32
Competitors in Russia .................................................................................................................... 32
Competitors outside Russia ........................................................................................................... 33 Methanol Processes: Methion vs Globotek ............................................................................... 35 Methanol Processes: Conventional vs Globotek ....................................................................... 37
Supply of Liquid Petroleum Gas (LPG) ............................................................................................ 39
Worldwide Supply ......................................................................................................................... 39 LPG Supply – Regions .................................................................................................................. 40
Demand for LPG ................................................................................................................................ 41 Demand Forecast ........................................................................................................................... 41 Worldwide Consumption of LPG ................................................................................................. 42
Leading LPG Markets Worldwide ................................................................................................. 43 Petrochemical market ................................................................................................................ 46 Autogas Market ......................................................................................................................... 46
LPG Transportation ........................................................................................................................... 47 Conditions for Transport ................................................................................................................ 47
Road Transport .......................................................................................................................... 48 Trains ......................................................................................................................................... 49
Shipping ..................................................................................................................................... 50 Routes to Market ............................................................................................................................ 52
Russia ......................................................................................................................................... 52 Transport from Kazakhstan and Turkmenistan ......................................................................... 53 Turkey ........................................................................................................................................ 55
2009 ii
Germany .................................................................................................................................... 56
India ........................................................................................................................................... 56 Methanol Market ............................................................................................................................... 57
Worldwide Demand ....................................................................................................................... 57
Worldwide Supply ......................................................................................................................... 58 Chinese Methanol Production .................................................................................................... 59 Russian Methanol Production .................................................................................................... 59
Transport of Methanol in Russia ................................................................................................... 60 Market prices ................................................................................................................................. 60
Future Demand for Fuel Cells ....................................................................................................... 61 Customer Proposal ............................................................................................................................. 61
Deal Terms Offered to Field Owners ............................................................................................ 62 Years for Off-Take versus Field Production Profile ...................................................................... 62 Screening Process & Budget ......................................................................................................... 65
Project Structure ............................................................................................................................ 65 Project Team .................................................................................................................................. 66 Project Time-Line .......................................................................................................................... 66
Project Financial Analysis ................................................................................................................. 70 Defining the Base Case .................................................................................................................. 70
Upside Case ............................................................................................................................... 75
Downside Case .......................................................................................................................... 76 Water Driven Field Analysis ......................................................................................................... 77
Base Case Assumptions Applied to Water Driven Field ........................................................... 77
Upside Case with Water Driven Field ....................................................................................... 78 Downside Case with Water Driven Field .................................................................................. 78
Solution Gas Field Analysis .......................................................................................................... 79 Sensitivity Analysis ....................................................................................................................... 80
Sensitivity Table with Gas Cap Field ........................................................................................ 82
Risks and Mitigations ........................................................................................................................ 85
Appendices ........................................................................................................................................ 91 General information about LPG .................................................................................................... 91
Definition and characteristics of LPG ....................................................................................... 91 Table Properties of LPG .............................................. Ошибка! Закладка не определена.89
Application and advantages of LPG .......................................................................................... 91 Table: LPG compared to petrol and diesel ................................................................................ 92 Formation and production .......................................................................................................... 92 Differences between LPG, LNG and CNG ............................................................................... 92
Globotek Licenses ......................................................................................................................... 94
Globotek‘s Patents ......................................................................................................................... 99 Gas Flaring Articles ..................................................................................................................... 111
Russia top offender in gas-flare emissions .............................................................................. 111
Fines for Burning Associated Gas Soar ................................................................................... 113 Nigeria: Norway to help cut down on gas flaring and oil spill ................................................ 114
Oil industry Jargon de-coded ....................................................................................................... 117 Completed project ........................................................................................................................ 123
New Documentary into Gas Flaring ............................................................................................ 126 Additional Due Diligence on Globotek ....................................................................................... 127
2009 iii
Index of Figures and Tables
Figure 1 - Traditional Gas Processing Plant ...................................................................................... 20
Figure 2 - Global Supply of LPG ...................................................................................................... 39 Figure 3 - Russia/ CIS Supply of LPG ................................ Ошибка! Закладка не определена.38 Figure 4 - Worldwide LPG Market ................................................................................................... 42 Figure 5 - Regional LPG Demand ..................................................................................................... 43 Figure 6 - Regional LPG Consumption ............................................................................................. 43
Figure 7 - LPG Market in Europe (excluding Petrochemicals) ......................................................... 45 Figure 8 - Consumption of LPG in The FSU ...................... Ошибка! Закладка не определена.44 Figure 9 - LPG consumption in the petrochemcial industry .............................................................. 46 Figure 10- LPG Transport Routes ..................................................................................................... 52 Figure 11 - LPG Terminal on the Taman Peninsula .......................................................................... 53
Figure 12 - LPG Storage facilities in Turkey .................................................................................... 56
Figure 13 - World Methanol demand (% growth year on year) ........................................................ 57 Figure 14 – Chemical Derivatives of Methanol ................................................................................ 58
Figure 15 - Methanol derivatives demand in the future .................................................................... 58 Figure 16 - APG from Water Driven Field ........................................................................................ 63 Figure 17 - APG from Gas Cap Driven Field .................................................................................... 64 Figure 18 - APG from Solution Gas Driven Field ............................................................................. 64
Table 1- Top Flaring Countries ........................................................................................................... 7
Table 2 – Associated Gas from Major Russian Oil Companies ........................................................ 12 Table 3 - LPG Container Specifications ............................................................................................ 48
Table 4 - Major Logistics Companies in Russia ................................................................................ 49 Table 5 - Monthly and Daily LPG Shipping Prices ........................................................................... 51
Table 6 - Largest Russian Methanol Producers ................................................................................. 59 Table 7 - Associated Gas Production by Reservoir Drive Mechanism ............................................. 63
Table 8 - Screening Budget for Project in Russia.............................................................................. 65 Table 9 - Project Time Line ............................................................................................................... 68 Table 10 – Sample APG Project Investment ..................................................................................... 68 Table 11 - Environmental differences between LPG, diesel and petrol ............................................ 92
Table 12- List of independent oil companies in Russia ................................................................... 122
2009 1
Executive Summary
Globotek Holdings Inc. is a business development and APG equipment trading company registered in
the USA (hereinafter, the ―Company‖ or ―GLOBOTEK HOLDINGS‖).
GLOBOTEK HOLDINGS proposes to capture and sell the associated gas from small to medium-
sized oil fields in exchange for bearing the costs of supplying and operating the required hardware.
Key components to this strategy are the Company‘s exclusive rights to propriety and patented gas
separation equipment, its low-cost manufacturing and assembly capabilities inside Russia and its
capable and experienced marketing staff. Combined these allow GLOBOTEK HOLDINGS to be
very profitable in fields that otherwise would flare 5-50 million cubic meters of gas per annum
(mcm). GLOBOTEK HOLDINGS can earn wide operating margins with small payments for the
associated gas, because oil producers face increasingly steep environmental penalties unless they stop
flaring this gas. Furthermore most of these producers would rather avoid investing in capital
equipment to reduce flaring, since without a nearby pipeline, they view associated gas as simply a by-
product to their core, oil production.
The business plan envisions initially screening 5-10 projects per year of which it will fully develop
roughly half. While various breakpoints are provided along the way, so as to drop any flawed project
early in the screening process, the full cost of engineering and commercial preparation of a project is
roughly $150,000 to $400,000. Manufacture, delivery, installation and start-up of a given gas
processing unit will require 8-16 months based upon its size and location bearing a capital cost of
~$5m for a 5 mcm unit up to ~$30m for a 50 mcm unit. Operating margins for selected projects will
be in the order of 40-80% providing return of capital in 2-4 years plus a dividend stream for at least a
further 3-6 years. Geographically the Company will start in Russia and the Former Soviet Union
(FSU)
GLOBOTEK HOLDINGS also sell feasibility study & projecting services and APG processing
equipment to the oil companies in FSU, expanding abroad into Nigeria and other oil producing
regions with high gas flaring.
GLOBOTEK HOLDINGS now seeks investment for its development activities as well as to construct
individual projects. The projects are expected to yield ~40% for its core gas plants producing LPG
and naphtha. Fortuitously, several such projects may now be developed in the European part of
Russia for modest capital expenditure and quick cash generation. Furthermore given the rush to
avoid pentalties on gas flaring and venting in Russia, competing manufacturers have scant capacity to
build such plants until 2012, making it easier for a new service provider to enter the market.
Beyond GLOBOTEK HOLDINGS‘s immediate set of projects, for fields that are remote from
municipalities and power lines, it may include power generators or methanol production units along
with its core plant. These plants are forecast to have returns in the mid-20% range. Nonetheless
GLOBOTEK HOLDINGS can reject projects which fail to meet its return objectives. Also, as a
given reservoir is drawn down and raw gas production declines, GLOBOTEK HOLDINGS can easily
redeploy its gas processing units to other fields so as to continue to generate income over 30+ year
life of the equipment and thereby boost its overall investment return.
2009 2
Background
Most crude oil contains about 2.5-5% of light hydrocarbons which become gaseous at surface
pressure. These gases associated with petroleum production are commonly referred to as Liquid
Petroleum Gas (LPG). These light hydrocarbons consist principally of propane (C3H8) and butane
(C4H10), but may also include pentane (C5H12) or natural gasoline1. This LPG must be separated from
crude oil at the production site before the crude can be transported by tanker or pipeline2.
Additionally, crude oil reservoirs often produce some quantity of methane (CH4) and ethane (C2H6).
Oil field operators have basically four options to remove the raw gases associated with crude oil
production:
Flare the gases
Reinject them into the field to increase or maintain reservoir pressure in support of crude
production
Use raw gases to generate electricity
Install production units to capture the ‗raw gases‘ as LPG, naphtha3 and methanol
1 Note: the gasoline sold at filling stations is a blend of various hydrocarbons from C5 to C10. Among these, natural
gasoline is the volatile fraction consisting of primarily of pentane and isopentanes which become gaseous above 36° C.
When produced from a gas well, pentane, hexane (C6H14), and heptane (C7H16) are referred to as Natural Gas Liquids
(NGL). For a more complete discussion of industry terminology see Appendix XXX. 2 For further information see Appendix XXX.
3 Naphtha is also referred to as natural gasoline or straight-run gasoline. It is used as a feedstock for reforming and as
petrochemicals. While definitions vary according to context, for the purpose of this report naphtha is understood to
comprise of pentane (C5H12) and hexane (C6H14) and heptane (С7Н16) along with their isomers.
2009 3
Given the adverse impact of flaring LPG World Bank and other governmental and regulatory
organisations increasingly advocate the conversion of these associated gases into liquid hydrocarbons
for easier transportation so as to:
Reduce emissions
Generate additional energy resources
Governments and producers have also become increasingly aware of the loss of both energy and
economic value caused by flaring and so is eager to put it to better use.
Business Proposal
More specifically, the GLOBOTEK HOLDINGS team proposes to:
Conclude long term contracts with producers for the exclusive supply of the gases wherein:
- The term of such contracts will exceed the pay back time of the plants for a minimum of
twice that length of time. For example, in the case of where the pay back time is planned
for 36 months, then the contract period to be minimum 84 months.
- Purchase the associated gas for free or for a very low fee so oil field owners avoid being
fined and having their permits revoked by the local and federal governments.
Alternatively a production sharing agreement will be negotiated whereby the least
acceptable figures would be 10% for producers until pay back and max 40% for
producers after pay
Implement the patented technology to separate the otherwise flared gas into its individual
constituents.
Transport and sell these individual constituents (e.g. LPG and naphtha) in Europe or at a rail
station close to the production site.
2009 4
- Shipping terms would be CIF4 if delivered to Europe or FCA5 at the domestic terminal.
Depending on location and thus isolation of the oil field decide whether sale of lighter gases (C1
–C2) outright, generation and sale of electricity or production and sale of methanol is best. Power
generation is usually easier but requires access to power lines. Meanwhile, though the most
costly option to construct, methanol production enables GRG to gain value from methane
production in isolated conditions.
Sell each product to their respective ready markets both globally and domestically.
- LPG is used primarily as a cooking gas but also increasingly for cars and in the
petrochemical industry.
- Naphtha is the traditional crude oil fraction used in the petrochemical industry
- The lighter gases (C1-C2) may be sold directly to local municipalities or local power
generators. Alternatively a given project may buy and operate its own power generators
or may add methanol production units to serve domestic or export fertilizer and
petrochemical markets.
Generate additional income from the sale of CO2 reduction certificates under the Kyoto Protocol
or other, similar schemes since projects that reduce flaring in developing countries generally
qualify as a Clean Development Project (CDM).
Establish special purpose vehicles (SPVs) for each project to hold the commercial contracts and
own the plant(s), thereby limiting the risk that difficulties with one installation could impinge
upon the operation of others.
Gradually build up a portfolio of projects to generate a self-sustaining stream of income to allow
the company to grow independently of external finance.
Expand its regions of operation where gas flaring is heavily penalised to maximise profits.
The GLOBOTEK HOLDINGS team shall:
Identify projects
Submit budgets
Undertake and execute the projects
Establish separate companies for each project
Sell the processed products
Run the productions plants
4 CIF (Cost, Insurance, and Freight): The seller's price includes cost of the goods, marine insurance, and all
transportation charges to the named destination point. Seller should specify CIF to maintain maximum control of the
shipment until the transaction has been completed. 5 FCA (Free Carrier At ... named place): The seller fulfills his obligation when he has handed over the goods, cleared
for export, into the charge of the carrier named by the buyer at the named place or point. If no precise point is indicated
by the buyer, the seller may choose, within the place or range stipulated, where the carrier should take the goods into
their charge.
2009 5
The investor shall:
Nominate their experts and managers for the project and/or confirm the team proposals in respect
to staff of the project
Advise about required due diligence
Finance 100 % of the budgets
Gas Flaring and Venting
Gas flaring occurs when associated gas from an oil field is burnt releasing carbon dioxide into the
environment. The process is often undertaken as it is too expensive and tricky to harness this gas and
bring it to market. The oil companies until recently have only been interested in producing crude oil and
therefore these gaseous fuels were considered by products
Venting is the controlled release of associated gases into the atmosphere in the course of oil and gas
production operations. The associated gases in this case are not burnt. The problem with this method is
that methane release is considerably worse than carbon dioxide as a GHG. Each gas is measured using
the Global Warming Potential (GWP) which is based on a number of factors, including the radiative
efficiency (heat-absorbing ability) of each gas relative to that of carbon dioxide, as well as the decay rate
of each gas (the amount removed from the atmosphere over a given number of years) relative to that of
carbon dioxide. The GWP is defined as the ratio of the time-integrated radiative forcing from the
instantaneous release of 1 kg of a trace substance relative to that of 1 kg of a reference gas. More
recently it is used as the official measurement to the Kyoto Protocol.6
Gas
Global Warming
Potential 7
Carbon dioxide 1
Methane 23
Nitrous Oxide 296
6 Intergovernmental Panel for Climate Change – Climate Change 2001: The Scientific Basis
7 IPCC estimates
2009 6
Until recently all countries combined the gas venting and flaring figure. It is only now when countries
such as Canada are encouraging legislation to spot the difference between the two operations. Argentina
is one of the few who have adopted a new policy which prevents flaring if the gas-to-oil ratio exceeds
100 mVm3.
Global Environmental Problem
The World Bank in May 07 after a twelve year8 study estimated that the annual volume of associated gas
being flared and vented is roughly 150-170 billion cubic meters (bcm), enough fuel to provide the
combined annual natural gas consumption of Germany and France. Flaring in Africa alone reached 37
bcm in 2000, which could produce 200 Terawatt hours (TWh) of electricity, which is about 50 percent
of the current power consumption of the African continent. It is widely acknowledged that flaring and
venting of associated gas contributes significantly to greenhouse gas (GHG) emissions and has negative
impacts on the environment.
Causes
In the past few firms utilized associated gas from the oil fields because -
- Lack of access to a gas pipeline system which reduced the scope for oil producers to extract
value from the associated gas
- There were no substantial environmental penalties for gas flaring
- Smaller oil producers did not have the capital power to invest in expensive equipment to
harness the gas. They preferred to concentrate on oil which provided guaranteed higher
returns
- Requirements of a functioning electrical system
- No access to the electrical system therefore no ability to produce electricity
- Reinjection was again considered an expensive approach.
Defence Meteorological Satellite Program (DMSP)
Mapping of Global Gas Flaring
8 A Twelve Year Record of National and Global Gas Flaring Volumes Using Satellite Data, Final Report to the World
Bank – May 30, 2007
2009 7
The World Bank study‘s satellite data – which is considered more accurate than self-reported country
data collected by the Global Gas Flaring Reduction initiative – reveals Russia to be the world‘s
largest flarer of associated gas wherein the Khanty-Mansiysk region on its own, flares more than the
whole of the next largest offender, Nigeria.
Table 1- Top Flaring Countries 2008 data
RANK COUNTRY BCM
1 Russia_Combined 40.56
Russia_not_KM (21.32)
Russia_KM (19.24)
2 Nigeria 15.05
3 Iran 10.39
4 Iraq 7.02
5 Algeria 5.54
6 Kazakhstan 5.22
7 Libya 3.75
8 Saudi_Arabia 3.51
9 Angola 3.12
10 Qatar 2.99
11 Uzbekistan 2.71
12 Mexico 2.61
13 Venezuela 2.57
14 Indonesia 2.32
15 USA_Combined 2.32
16 China 2.30
17 Oman 1.90
18 Malaysia 1.87
19 Canada 1.82
20 Kuwait 1.81
The National Geophysical Data Centre – who collate data for the World Bank – have also studied
changes in flaring year on year. The largest increase was in Mexico with just over 0.8bcm/year from
2007 to 2008. The largest decrease actually occurred in Russia with an 11 bcm fall between 2007-
2008. This is a large decrease but as it is still the largest flarer in the world just indicates the challenge
ahead to completely eradicate flaring worldwide.
2009 8
Source: The Infrastructure Challenge, Dr. Mostefa Ouki, Manager, Oil & Gas, Nexant, UK, presentation at the Global
Forum for Flaring Reduction & Gas Utilisation, Paris: 13 – 15 December 2006
Most governments in oil-producing countries have acknowledged the role gas flaring and venting
reductions can play in achieving overall environmental objectives and emission targets. Natural gas
prices have increased substantially since the early 1970s, and governments and industry increasingly
recognize the potential economic benefits of using associated. However, only a few oil-producing
countries have significantly reduced associated gas flaring volumes, and in most jurisdictions flaring and
venting volumes continue to rise with increased oil production. Regulation can play an important role in
reducing flaring and venting especially in the largest gas flaring nations.
Focus on Russia
Gas producers in Russia will be interested in GLOBOTEK HOLDING‘s proposal because of
regulations requiring 95% of associated gas to be utilised. Since September 2007 a tax (NDPI) of
RUR147/ 1000 m3 has been enforced by the State for flaring associated gas. According to Ministry
of Natural Resources (MNR) these taxes will be increased each year until flaring becomes
uneconomic. Other proposals envision flaring to become totally illegal and cause an oil production
license to be cancelled. Already the MNR will not approve development projects that do not have gas
utilisation of at least 95% by 2011.
LPG production in Russia is growing fast: Expected annual volumes to grow by several million
tons in Russia from current production of about 5-6 million (mln) tons; up to 3 mln tons from
currently 1 mln tons in Kazakhstan and approx. 1.5 mln tons in Turkmenistan from currently 0.4
mln tons (√ stats).
Russian Crude Producers like Negusneft, Chernogorkoje, Geoilbent, SamaraNafta and Elek-neft
(subsidiary of Tatneft) are ready to work on the following basis:
Sign a long term contract for the exclusive supply of all associated gases flared for a very low
price or at no cost.
The ‗team‘ will be responsible for the installation of the LPG production unit and all the logistical
equipment.
Pay backs are linked to effective sale of LPG and other products/electricity/heat
2009 9
There could be additional income created from the sale of emission certificates under the Kyoto
Protocol
The current LPG production of 2 mln tons per annum in Russia will increase to 5 mln tons per annum
until 2010-2015. Hundreds of millions of cubic meters of raw gases are still getting flared in the FSU
(‗the noise like roaring trains from these flares is like it was in the North Sea in the seventies‘). LPG
production will increase because:
New oil wells are prohibited to undertake flaring of gases – no licenses are granted if solutions
are not presented. Therefore new wells must either produce LPG or reinject the gases
Raw gases are getting taxed as crude oil production
Flaring of gases is getting taxed, penalized and prohibited – also on existing wells
While work by the World Bank‘s, Global Gas Flaring Reduction initiative, has raised awareness of
the problem, Russia‘s petro-affluence has brought with it increasing concern for the environment as
well as the considerable loss of income from such practices.
Russia is considered the largest gas flaring nation in the world. Even the Khanty-Mansiysk region, on
its own, flares more than the whole of the next largest offender, Nigeria.
For this reason the authorities within Russia and worldwide are putting pressure on the heads of
industry to come up with better methods to deal with the problem. To encourage such a measure
Russia has attempted to put in place tariffs / fines if companies continue to flare associated gas which
is both damaging to the environment and lost revenue for the country ($13 billion in 2006). As of
September 2007 a tax (NDPI) of RUR147 per 1000 m3 has been enforced by the State for flaring
associated gas which is thought will rise until flaring becomes uneconomic, even to the most isolated
oil fields. More drastic proposals on the table envision flaring to become totally illegal and could lead
to the cancellation of an oil production license. Already the Ministry of Natural Resources (MNR)
will not approve development projects that utilize less than 85% by 2011 rising to 95% by 2015 as
production shifts from brown-field wells to green-field development of new oil fields.
As it stands current LPG production has reached 5-6 million tons and increasing by 2 million per year
as gas prices have made the capture more economically attractive. However the product is still not
completely viable as at least 24.4 % of the 58 bcm of associated gas produced was flared in 2006. If
you exclude the region of Khanty-Mansiysk (K-M), Russia has increased gas flaring by 10 bcm since
1996.
Russia (excluding K-M) gas flaring estimate from the Defense Meteorological Satellite Program -
2009 10
Russian domestic policy has left associated gas prices well below regulated natural gas prices in oil
producing areas such as Khanty-Mansiysk where associated gas prices are RUB913/mcm
($35.1/mcm). Given that oil companies argue that gas collection and delivery of associated gas needs
a price of around $50/mcm to justify new investments, the policy discourages gas utilisation at a time
of supposed gas shortages.
In accordance with this problem the FTS scrapped all state regulation of prices for associated gas,
which points to an eventual liberalisation of the domestic LPG market9.
In the meantime, oil companies such as TNK-BP and TNBPI.RTS and Rosneft unveiled plans to
allocate around US$6 billion to reducing flaring after Vladimir Putin called on them to reduce flaring
to 5 percent by 2011 from over 25 percent at the moment.10
Thanks to such initiatives as, Global Gas Flaring Reduction, it has raised awareness of the problem
and lead President Putin to allude to the problem of gas flaring in his Apr 2007 address to the nation
address. Soon thereafter the Ministry of Natural Resources, the Russian environmental watchdog
Rosprirodnadzor and the technical watchdog Rostekhnadzor announced they are considering
measures to discourage gas flaring.
A sign that times are changing:
The Decree of Russian Government dated January, 8, 2010 puts the deadline to obtain 95% of
APG Utilization till 01/01/2012 with severe penalties to the oil producers not able to meet that
requirement.
In August 2007 Gazprom Neft and Sibur announced a $600m joint venture to process associated
gas from the Yuzhno-Priobskoye field in West Siberia which is part of Sibur‘s plan to increase
the annual volumes of associated gas it reprocesses, from the current 14 bcm to 22 bcm by 2011.
Similarly, the Expert Daily reported that Rosneft and TNK-BP, responsible for 35% and 22% of
the associated gas flared respectively, are finding ways to refine associated gas11
.
Acting Russian First Deputy Prime Minister Sergei Ivanov said at a meeting of the military
industrial commission in Khanty-Mansiisk on September 13 2007 that Russia would soon stop
flaring petroleum gas altogether.12
On September 19 2006 Lukoil announced via Interfax that it would invest 50 billion rubles in 125
projects to utilize associated petroleum gas between 2007 and 2010. The projects aim to raise the
utilization rate from 75% to 95% at existing fields, and 100% utilization from new fields.13
In October 2007, Surgutneftegaz stated its intention to use 96% of its associated gas from its
operations in Khanty-Mansiysk and Yamal-Nenets by the end of 2008, according to CEO,
Vladimir Bogdanov.14
Rosneft intends to spend 67 billion rubles within five years to boost the disposal of associated gas
from only 59% to 95% by 2011.15
9 Reuters : Russia scraps state caps on associated gas prices
10 Companies commit cash to associated gas disposal, RBC DAILY, October 11, 2007
11 Russia turns down the heat, FSU Oil & Gas Monitor, 22 August 2007, Week 33, pp. 2-3
12 Lukoil To Invest 50 Bln Rubles In Associated Gas Utilization, Russia & FSU Oil and Gas Weekly, September 13,
2007 - September 19, 2007, N 37 (805), p. 29 13
Op Cit, p. 13 14
Russia works on gas flaring reduction, FSU Oil & Gas Monitor 03 October 2007, Week 39, p. 8 15
Rosneft to invest in associated gas, FSU Oil & Gas Monitor 17 October 2007, Week 41, p. 19
2009 11
In the Samara region [in late September] legislation required oil companies to install counters on
their mining sites in order to provide more information as to how much associated gas was
produced16
.
16
Ibid, FSU O&G Monitor
2009 12
Table 2 – Associated Gas from Major Russian Oil Companies
Companies
Associated
gas
production Utilized Flared
Mln m³ % Mln m³ % Mln m³ %
Surgutneftegas 15,416.8 27.4 14,361.0 93.2 1,055.8 6.8
ТNK-ВР
holding 10,699.2 19.0
8,302.3 77.6 2,396.9
22.4
Rosneft 8,489.1 15.1 5,311.1 62.6 3,178.0 37.4
Lukoil 6,151.3 10.9 4,767.8 77.5 1,383.5 22.5
Gazprom Neft 5,660.9 10.1 1,985.3 35.1 3,675.6 64.9
Yukos 2,605.3 4.6 1,964.4 75.4 640.9 24.6
Slavneft 1,532.6 2.7 994.1 64.9 538.5 35.1
Russneft 1,555.4 2.8 1,057.5 68.0 497.9 32.0
Тatneft 770.7 1.4 736.7 95.6 34.0 4.4
Bashneft 429.0 0.8 333.0 77.6 96.0 22.4
Other 2,889.7 5.1 1,486.8 51.5 1,402.9 48.5
TOTAL 56,200 100 41,300 73.5 14,900 26.5
Source: Natural Resources Policy Department, Fuel & Energy Complex, Ministry of Industry & Energy of the Russian
Federation, Dec-06 presentation at Global Forum, Flaring Reduction & Gas Utilization
While Russia has some very large oil producers whose production subsidiaries may contract with
GLOBOTEK HOLDINGS/Globotek, the greater source of potential customers are Russia‘ 150
small and mid-sized producers who are more likely to have fields producing between 5-50 million
cubic meters per annum of associated gas and natural gas liquids.
For a list of independent crude oil producers in Russia, see Appendix.
Focus on Kazakhstan
Kazakhstan currently produce 3 mln tons of LPG up from 1 mln tons in previous years. This figure is
set to grow for the foreseeable future as the government become less tolerant of gas flaring. As it
stands 23 LPG production plants are to be constructed at oil and gas fields to encourage companies to
harness the gas which is an financial los to both the government and producer.17
In past Kazakhstan
has attempted to abolish flaring, however oil producing companies protested about the severity of the
fines and the limited time in which to prevent flaring.
Currently the largest LPG producer in Kazakhstan is TCO with some 800 KT per annum. Other giant
Oilfields like Kachagan (off shore North Caspian Sea) have so far opted against LPG production in
favour of reinjection of gases. Companies like Kasgermunai (in production since 2005) and Ascom
(after 2007) collectively produce 100-200.000 KT of LPG per annum.
17
http://www.energyintel.com/Trial.asp
2009 13
There are so far 10 plants within Kazakhstan where GLOBOTEK HOLDINGS would consider
production. GLOBOTEK HOLDINGS has approached and been approached by companies such
as, but not restricted to:
South Oil
Dolinoe
CaspiNeft TME
Adaoil
OOO Kondensat www.condensate.kz
Armangirldi
Kasmunaigas
Focus on Turkmenistan
Turkmenistan currently produces 400-600 KT per annum which is exported to Russia (for transit),
Iran and other neighbouring countries like Afghanistan. This figure is expected to rise to 2 mln tons
per annum as the government hope to take advantage of a valuable resource.
GRG‘s main target customer would be Turkmengas – the state Oil Company. Negotiations have taken
place with Turkmengas to enable GLOBOTEK HOLDINGS to run projects from a numerous
number of sites. The agreement with such a company would involve -
A production sharing agreement is unavoidable
Initial and very rough conditions can be described as follows:
- plant prices/investment costs to be adjusted for local conditions
- PSA ratios to be 60-80 % to investors before pay back and 20-40 % after pay back
- Surrounding conditions in Turkmenistan like water and power supply shall be checked
thoroughly
Focus on Nigeria
Nigeria is the second largest gas flaring country in the world after Russia. Similarly legislation is
beginning to be enforced to prevent backlash from the world stage against environmental pollution.
In Nigeria 42 per cent of the associated gas is being flared, down from the 62 per cent in 2000. The
latest government act to impose a no flaring policy by 2010 has lapsed while pressure from activists
becomes even more desperate.
2009 14
However compelling evidence that policy is aiming to correct the problem, Nigeria's department of
petroleum resources (DPR), increased the gas flare penalty from an insignificant $0.7 (10 Naira) per
1000 standard cubic feet of gas to $3.50 with effect from December 31, 2008.
At the moment Nigeria raise only US$150,000–370,000 annually for penalties for associated gas
flaring but it is estimated that the country loses between US$500 million and US$2.5 billion in gas
flared.
Nowadays the government is to insert clauses in new contracts insisting that associated gas must not
be flared. Nigeria insists that failure to comply will result in contracts being revoked.
GLOBOTEK HOLDINGS had just signed the 10 year License Agreement to build minimum 1 APG
processing plant per year in Nigeria.
Other Nations
Once a common industry practice, flaring is now widely discouraged, and many countries, like
Nigeria are instituting anti-flaring or emission policies and taxes to discourage wasting gas. Anti-
flaring taxes are likely to expand as local governments try to capture more value from their reserves.
As such penalties for flaring are imposed; the incentive to market the gas will increase. In addition, a
growing list of multi-national energy companies is introducing policies to reduce or halt flaring and
pushing the development of gas conversion technologies. The World Bank‘s Global Gas Flaring
Reduction (GGFR), is assisting countries like Algeria, Angola, Kazakhstan, Nigeria, and Qatar to
meet identified dates for zero flaring, through increased collaboration between operators, the national
oil company and the regulator.
In the case of Algeria, $600 million has been spent on gas flaring reduction projects since 1973,
reducing gas flaring from 84 per cent of associated gas production to about 11 per cent today. The
national oil company, Sonatrach, plans to reduce this to zero by 2010, primarily through re-injection.
In Angola the state Company ―Angola LNG Limited‖ aims to capture LNG off-shore and on-shore.
This will have a positive impact on revenue for the country and the environment. As a recent member
of the GGFR project such initiative is encouraged and helps towards a zero–flaring policy in the
coming years.18
Gas sells at very low prices in some countries, especially in West Africa — less than $0.25 MMBtu
— so additional efforts need to be taken to address flaring, often in conjunction with economic
development and employment initiatives.19
These countries and others are building specialized gas-
conversion hubs where numerous plants are located in close proximity. By creating these hubs,
planners can allow multiple facilities to share processing and pre-treatment infrastructure, ports,
administrative offices, fire-fighting equipment, skilled labour and other specialized resources to
mitigate capital costs. As a result, gas-rich nations diversify revenue while allowing developers to
reduce capital costs.
18
Oil and Gas Industry Codes of Conduct and Angolan National Legislation 19
HIS Energy – The Economics and Opportunities of stranded gas.
2009 15
At a recent UN-supported high-level meeting on hydrocarbon development a Qatari spokesperson
outlined their policy for a zero tolerance towards gas flaring. As a recent member of GGFR, attempts
to clean up flaring are being put in place. Qatar has so far commissioned a National Emission
Inventory to gauge the production level of emissions relating to flaring. The plan is to provide finance
and incentives for oil fields and refineries to stop flaring. So far no date has been put on this
development, but the intention is promising.20
Clean Development Mechanism
As the concept of flaring releases CO2 into the atmosphere at a rate of roughly 300 million tons per
year it contributes significantly to global emissions of greenhouse gases. The Global Gas Flaring
Reduction Public Private Partnership (GGFR) was established to supplement and strengthen efforts
made by governments and companies to reduce and eventually eliminate flaring. GGFR involves the
World Bank and other stakeholders, including governments and oil & gas companies. GGFR aims to
curb flaring by using the Clean Development Mechanism (CDM) of the Kyoto Protocol (KP) to
reduce greenhouse gas emissions (GHG) as an effective financial incentive. These projects will in
turn be instrumental in defining and furthering the role of the CDM in gas flaring reductions.
The CDM allows companies with approved projects in developing countries, which reduce emissions,
to sell the emission credits to developed countries that must reduce their emissions (Annex I under the
KP). The main goals of this mechanism are to assist Annex I countries in reaching their emission
reduction targets and promote sustainable development in the developing countries. This guidebook
explains the characteristics of the CDM and describes in detail how companies can create an
additional revenue stream from gas flare-out projects by including carbon credits obtained through the
CDM mechanism. It also relates the CDM and its applicability to the Nigerian situation. Nigeria is
eligible to participate in this mechanism since it has already ratified the Kyoto Protocol in 2004 and it
has high potential for emission reduction projects, in particular in the oil and gas sector.21
The Italian oil company ENI has already taken this initiative and set up a power plant to burn the
otherwise flared gas in Nigeria. Such a scheme qualifies for a CDM project.
siteresources.worldbank.org/EXTGGFR/Resources/NigeriaGGFRGuidebook_ICF.pdf –
GLOBOTEK HOLDINGS Technology Partner
& 100% subsidiary – JSC ―Globotek‖(Russia)
Globotek is a technology and manufacturing company who sells patented technology to potential
producers of associated gas and methanol. The technology is especially adapted to oil fields
producing between 10-50 mln m3 of associated gas a year.
The unique selling points of Globotek are as follows:
Costs and performance are allegedly better than other gas processing companies especially in the
fields between 10 to 50 mln m3 of associated gas.
20
Gulf Times – QP sets zero gas flaring target 21
Nigeria: Guidebook for Carbon Credit Development for Flare Reduction Projects, ICF International, June 2006
2009 16
Developed in Russia for the Russian market; avoids bureaucracy and transport time
Newly patented technologies for the capture of associated gas and production of methanol using
the Fischer – Tropsch method.
Experienced management team in respect to technology, logistics, consulting and international
sales
Globotek has already taken on a small number of projects in Russia with associated gas. The results
so far have demonstrated the great selling point of Globotek‘s patented technology for gas fields
between 10 to 50 mln cbm3 of associated gas. For wider deployment outside of Russia, the actual
construction and engineering could be best achieved by partnering with a Western engineering firm.
This would provide performance guarantees for LPG production as per EU standards governing such
things as octane number, water content and odour.
Overview of Globotek
Globotek is a Russian, Closed Joint Stock Company which is both a developer and fabricator of gas
processing equipment. The company is based in Tolyati, the second largest city in the Samara region
in the south-eastern part of the European Russia in the middle part of the Volga River.22
Globotek was established in 2005 with the aim of solving complex technological tasks on the basis of
scientific developments, performed during research and manufacturing activities of our team.
Founders of Globotek acquired the Tolyati factory in 2003.
During 2002-2009 Globotek‘s scientific-research and engineering centre has developed new unique
schemes of crude-associated gas utilization, production of methanol from crude-associated gas,
production of urea-formaldehyde concentrate from methanol, production of melamine, electricity
generation driven by non-traditional fuel, etc.
The Ministry of Natural resourses and Ecology of Russia had granted JSC ‖Globotek‖ with a reward
―The best ecological project of 2008‖.
The Monopolies Commission of the Russian Parliament has requested that Globotek, participate in
rewriting and creating new Federal laws that govern APG production and treatment in Russia and ng
concluded that Globotek should build 14 APG plants with a total processing capacity of 870 million
cubic meters during 2010-2011..
Globotek has received the endorsement by the Ministry of Energy of Russia due to the fact that
technology of Globotek is both efficient and economical and is now considered the leading solution
for APG processing directly at the oil fields.
Today Globotek offers:
Systems design.
22
For a regional profile of Samara see http://www.russianamericanchamber.org/regions/samara.html
2009 17
- Modern software (Compass, E-Plan, Scad Office) and other licensed programs (Teplos,
Technolog, PVB) are in use during project design.
- 3D visualization
Engineering of crude-associated gas processing devices including:
- Project development, project operation, project siting, constructing, technical, scientific and
engineering documentation.
Specific applications include:
- Drying and cleaning of crude-associated gas from water and sulphur compounds, for further
use as a fuel in gas turbines and gas reciprocating-engines with capacity up to 1 Billion m3
per year.
- Fraction separation from crude-associated gas for LPG, natural gasoline and natural gas
(methane).
- Methanol production with capacity of 10,000 – 450,000 tons per year.
- Ammonia production with capacity of 100,000 – 500,000 tons per year.
- Urea production with capacity of 50,000 – 300,000 tons per year.
- Melamine production with capacity of 10,000 – 50,000 tons per year.
- Other chemical products such as aromatic hydrocarbon concentrates.
―Key turn‖ production and construction of crude-associated gas processing devices.
Globotek develops and builds complete installation for crude-associated gas processing jointly
with the oil company.
Technological blocks assembling.
- Globotek has its own industrial plant (see below). All parts produced by contractual partners
are subjects to 100% incoming quality control. Pre-assembled units are overhauled and
quality tested with the use of modern non-destructive technologies
Services of testing, tooling, launching, engineering documentation developing, getting all
permissions for exploitation, personnel training and products certification for GOST, ISO, etc.
Globotek offers to buy crude-associated gas from the oil company
Globotek can develop packaged solutions for a license agreement with an oil company. These
would consist of:
- Researches, surveys, business plan drafting, investment grounding, engineering,
manufacturing, assembling, testing, tooling and launching of the equipment and personnel
training.
- Globotek may assist in designing engineering documentation for the development of oil field.
The company consists of the following departments:
Scientific & Manufacturing: develops regulations for engineering, projects, working projects,
constructing, technical, scientific and engineering documentation.
Construction & Assembly: places the orders for equipment and builds the installations from the
beginning till ―key turn‖ readiness.
Maintenance & Exploitation: organizes gas processing, further production, storage, sales and
transportation logistics.
Director of Scientific & Manufacturing Department
2009 18
Mr. Alexander N. Lapkin – the honoured chemist of Russia and arguably Russia‘s leading scientist
for gas processing.
Lapkin‘s scientific-engineering team has designed, developed, performed and presented at official
State commissions following projects:
Hotels at Tolyati, Gelendshk (Black sea area), Temryk (Azov sea area)
Recreational area with parking complex at Tolyati
Sanitary complex at Tolyati,
Sanatorium at Tolyati
Gas stations at Tolyati
Railway terminal for ammonia trans-shipment at Saratov
Sea terminal for ammonia trans-shipment at Shelezny Rog (Black sea)
32 km railway road in the Krasnodar region.
Complex for methanol production from ammonia in Tolyati
Complex for urea-formaldehyde concentrate production in Tolyati
Complex for urea-formaldehyde tar production in Sheksna.
Railway terminal for loose cargo trans-shipment in Hungary,
Sea terminal for ammonia trans-shipment in Turkey.
Crude-associated gas processing complexes in Orenburg & Nadum & Amangeldy (Kazakhstan)
– projects only
- These were engineered up to an extent, but were not completed or built, since the owners of
the raw gas did not have (or want to spend) the money
Manufacturing plant / facility in Tolyati
The industrial complex consists of three factories with more than 1,500 workers.
Plant Size Built
6,000 m3 1950
5,000 m3 1975
100,000 m3 1995
Several businesses are conducting operations from the complex which include:
- Globotek-NV; The operator of APG processing plant built by JSC ―Globotek‖ in Syberia (at
Mohtikneft oil field)
- Grinpal; A company that specializes in the Recycling of raw plastics.
- Polad; The manufacture of metal parts & equipment for Avtovaz, the producer of Lada cars.
While the landlord of the industrial facility (which it acquired in 2003) has common shareholders
with Globotek, there are no managers in common. The technical staff have always worked
exclusively for Globotek at the industrial plant and APG processing facility at Mohtikneft.
Within this complex Globotek operates out of two buildings which combined 11 000 m2 of floor
space, tens of machinery pieces which are useful for welding and assembly the gas processing
units. Testing is done separately in Globotek‘s laboratory
- Globotek employs 57 workers directly but can draw on other workers from the complex as
required.
The industrial complex is well served by transportation infrastructure:
- Two of the three factories are served by a railhead
2009 19
- Raw materials cannot be received directly from the Volga which lies about 10 km away, but
can be easily transported by truck along well maintained roads to the factory site. There is no
size limit for truck transportation. For example, the units for the plant at Mohtikneft (5 pcs, 3
x 3 x 9 meters each) were loaded to heavy trucks convoy.
- The Samara airport is reasonably close at a distance of 50 km.
Core Technology
This technology section starts with a review of conventional technologies which experienced readers
may wish to skip over.
Conventional technologies for associated petroleum gases
Separating Methane from Raw Natural Gas23
There are quite literally hundreds of different equipment configurations for the processing required to
separate natural gas condensate from a raw natural gas. The schematic flow diagram below depicts
just one of the possible configurations.
23
See Wikipedia, Natural Gas Condensate, en.wikipedia.org/wiki/Natural_gas_condensate
2009 20
The raw natural gas feedstock from a gas well or a group of wells is cooled to below its hydrocarbon
dew point which condenses a good part of the gas condensate hydrocarbons. The feedstock mixture of
gas, liquid condensate and water is then routed to a high pressure separator vessel where the water
and the raw natural gas are separated and removed. The raw natural gas from the high pressure
separator is sent to the main gas compressor.
The gas condensate from the high pressure separator flows through a throttling control valve to a low
pressure separator. The reduction in pressure across the control valve causes the condensate to
undergo a partial vaporization referred to as a flash vaporization. The raw natural gas from the low
pressure separator is sent to a "booster" compressor which raises the gas pressure and sends it through
a cooler and on to the main gas compressor. The main gas compressor raises the pressure of the gases
from the high and low pressure separators to whatever pressure is required for the pipeline
transportation of the gas to the raw natural gas processing plant. The main gas compressor discharge
pressure will depend upon the distance to the raw natural gas processing plant and it may require that
a multi-stage compressor be used.
At the raw natural gas processing plant, the gas will be dehydrated and acid gases and other
impurities will be removed from the gas. Then the ethane (C2), propane (C3), butanes (C4) and C5 plus
higher molecular weight hydrocarbons (referred to as C5+) will also be removed and recovered as by-
products.
Figure 1 - Traditional Gas Processing Plant
The water removed from both the high and low pressure separators will probably need to be
processed to remove hydrogen sulfide before the water can be disposed of or reused in some fashion.
Some of the raw natural gas may be re-injected into the gas wells to help maintain the gas reservoir
pressures.
Different methods of removing gas condensate from Natural gas24
24
http://www.petrostrategies.org/Learning%20Center/Gas_Processing.htm
2009 21
Natural gas liquids are recovered using four different technologies: refrigeration, cryogenic recovery,
oil absorption, and dry-bed adsorption. Natural gas liquids are recovered by cooling or refrigerating
the natural gas until the liquids are condensed out. The plants use Freon or propane to cool the gas.
Cryogenic recovery processes are done at temperatures lower than -150 °F. The low temperatures
allow the plant to recover over 90% of the ethane in the natural gas. Most new gas processing plants
use cryogenic recovery technology. Oil absorption is a process used by older gas processing plants
and in many refinery gas plants.
This process is not as efficient as cryogenic processing and only 70% propane and all of the butane
and natural gasoline are recovered. Dry-bed adsorption is used to remove water and some of the
natural gas liquids from the natural gas. The liquids are adsorbed on the surface of the desiccant such
as silica gel. Desiccants are added to many products, such as medicines, to keep them dry. The
adsorption process recovers 10 - 15% of the butane and 50 - 90% of the natural gasoline. After
removal from the natural gas stream, the natural gas liquids are separated in a series of distillation
towers into their primary components: ethane, propane, butane, and natural gasoline.
Methane to Methanol25
Methane or natural gas is converted to methanol via the intermediate production of synthesis gas (syn
gas)… Three processes are commercially practiced. At moderate pressures of 1 to 2 MPa (10-20 atm)
and high temperatures (around 850°C), methane reacts with steam over a nickel catalyst to produce
syngas:
CH4 + H2O → CO + 3H2
This reaction, commonly called steam-methane reforming, is endothermic and the heat transfer
limitations place limits on the size of the catalytic reactors used.
Also methane can also undergo partial oxidation with molecular oxygen to produce syngas:
2CH4 +O2 → 2CO + 4 H2
This reaction is exothermic and the heat given off can be used in-situ to drive the steam- methane
reforming reaction. When the two processes are combined, it is referred to as autothermal reforming.
The ratio of CO and H2 can be adjusted by using the water-gas shift reaction to provide the
appropriate stoichiometry for methanol synthesis:
CO + H2O → CO2 + H2,
The carbon monoxide and hydrogen react on a second catalyst (mixture of copper, zinc oxide and
alumina) to produce methanol. At 5 -10 MPa (50-100 atm) and 250°C, it can catalyze the production
of methanol from carbon monoxide and hydrogen with high selectivity:
CO + 2H2 → CH3OH
It is worth noting that the production of synthesis gas from methane produces 3 moles of hydrogen for
every mole of carbon monoxide, while the methanol synthesis consumes only 2 moles of hydrogen
for mole of carbon monoxide. One way of dealing with excess hydrogen is to inject carbon dioxide in
to the methanol synthesis reactor, where it, too reacts to form methanol according to the chemical
equation:
CO2 + 3H2 → CH3OH + H2O
25
http://en.wikipedia.org/wiki/Methanol
2009 22
Although natural gas is the most economical and widely used feedstock for methanol production,
other feedstocks can be used. Where natural gas is unavailable, light petroleum products can be used
in its place. The South African firm Sasol produces methanol using synthesis gas from coal.
Globotek‘s technology for associated petroleum gas
Today Globotek holds two patents to separate and liquefy associated petroleum gas. These cover:
Gas separation methodology and equipment
Methanol recovery methodology
Together these patents allow Globotek to build processing units which are robust and inexpensive, yet
which generate a narrower product mix than larger-scale and more complex processes. More
explicitly, Globotek produces three marketable products – LPG, naphtha and methanol – whereas
large scale plants typically produce individual streams of methane, ethane, propane, butane,
isobutene, pentane and may upgrade these into fertilizer, petrochemicals and/or plastics.
Yet by providing a simple product slate Globotek offers a very attractive option for associated gas
from oil fields located too far from or with quantities too small for a conventional gas processing
facility. The critical distance can vary from as little as ~10 to as much as ~300 kilometres depending
upon terrain, starting location and the cost of pipeline construction. While pipeline costs will vary by
region of the world and by proximity to metropolitan areas, in Siberia a raw-gas pipeline over level
ground currently costs about RUR 10-15mn ($0.4-0.6mn) per kilometre, such that a $10mn gas plant
for a smaller field becomes competitive at 17-25km.
2009 23
Gas Separation
Globotek‘s equipment prepares the raw-gas by removing sulphur compounds, water and sediments; it
then condenses the gas before separating and fractionating it. However, while conventional processes
condense and separate associated gas in discrete stages, Globotek‘s patented methodology condenses
them gradually while simultaneously dividing the propane-butane fraction from naphtha (natural
gasoline). The composition of the propane-butane blend at the end of the installation is in compliance
with the requirements of the Russian State Standards (GOST) for natural gas fuel (PGG).
It is worth noting that GOST standards are as strict if not stricter than EU standards26
for such things
as the purity of gas, the level of contaminants, the amount of water vapour, etc., with one exception,
namely sulphur. Here GOST allows 0.05% sulphur, however, Globotek‘s process reduces sulphur to
0.001% (or 10 parts per million) in its LPG which matches the lower boundary of the EU‘s EN 589
specification.
Normally the ratio of propane to butane is governed by the content of raw gas which typically ranges
60-80% of propane to 40-20% butane. However, certain countries mandate specific ratios such as
80:20 or in Turkey which requires 50:50. Globotek can adjust its equipment to fit the proper blends
of propane to butane for a given market, but this is more of a marketing, than a technical decision,
since at any blend that differs from the ratio found in the raw gas will result in less finished product.
Methanol Recovery
Rather than require pre-treated hydrocarbon gas, Globotek‘s patented technology for producing
methanol is attractive because it can utilise raw gas with unstable components and large amounts of
inert gases. This process makes maximum use of the raw hydrocarbons (methane and ethane) via
efficiently re-injecting the exhausted and unprocessed gas fractions back into the inlet of the
cascading chemical reactors.
Methanol recovery method consists of an inlet for the hydrocarbon gas to be treated, desulfurization,
catalytic steam conversion with converted gas recovery, heat utilization with water separation,
methanol synthesis and condensed methanol separation. It differs in the following:
Input of the hydrocarbon gas with an unstable composition goes under pressure of not less than
0.001 MPa;
Desulfurization of the hydrocarbon gas with an unstable composition is carried out together with
stepwise pressure stabilization phase and steam-gas mixture generation;
Methanol synthesis is carried out not less than through two consequent flowing stages with
catalyst volume reduction at a pressure of not less than 1.5 MPa;
Methanol separation is carried out between consequent stages;
Stepwise gas pressure stabilization is carried out via gas jet aggregates.
26
The quality of automotive fuels in the European Union is specified by standards developed by the European
Standards Organization (CEN). The first set of standards for automotive fuels, ratified by CEN on 16 March 1993,
became mandatory in all Member States by September 1993. Three standards cover automotive fuels quality: the EN
590 for diesel fuel, the EN 228 for gasoline, and EN 589 for automotive LPG. The standards are periodically updated to
reflect changes in specifications, such as the mandatory reductions in sulfur content.
2009 24
Competitive advantages of these technologies
Low unit energy costs for comparative product yields
- ~1/3rd
less than competing technologies
Modular construction allowing quick redeployment of processing blocks to other sites as a given
field declines
- Processing facility (or part of it) can be moved quickly to another source of crude
associated gas source
- This is very important, because the gas quantity at an oilfield has the tendency to decline
after 3-5-7 years and parts of equipment may be easily relocated to another oilfield
following such a reduction in quantity enabling the processing units to always work at
90-100% of their design capacity.
Deployment in close proximity to the wellhead, so no need for long delivery pipelines
Full operational autonomy
Minimum site preparation for the complex which dispenses with the need for capital construction
Low cost for installation of the complex; about 40% less than competing designs
- This shortens payback period.
In-house engineering and fabrication facilities capable of handling any type of associated gas
input allows Globotek to develop and manufacture treatment plants for a wide variety of fields,
including quite large-scale facilities. Production yield depends on gas compound.
Maximum and minimum processing amounts
In conditions of Russia, maximum competition advantages have facilities with input in the range
of 5 - 100 million m3/year of crude associated gas.
Globotek‘s engineering staff lets it develop and produce facilities for different inlet gases and for
a range of operating scales. Production yield depends on gas compound.
Fast installation
Globotek needs 6 - 12 months from beginning development until commissioning of the facility.
Even here lead times depend more on partners – parts producers, and especially, on compressor
aggregates producers, etc. – than on Globotek‘s work
By comparison, competitors require 12 -36 months from design to commissioning of associated
gas projects in Russia
Licensing and State Control
The modular construction of Globotek‘s installation is not regarded as capital construction and
therefore does not require going through multiple bureaucratic procedures in order to get
construction permits.
RosTekhnadzor currently has fully approved the technical assignment and documentation, and
usage license is granted, so as Certificate for serial industrial production and Quality Certificate.
2009 25
As the required testing of a given plant has been completed and series approval (so called TU)
has been granted, it is be possible for Globotek to produce a substantially similar installation
without obtaining a separate approval.
Equipment Manufacture
Quality control
Globotek‘s gas processing units are made with a combination of outside and in-house built
components.
All components go through compulsory quality control. Both outside and internal components are
carefully tested under close control (stability, density) by modern non-destructive testing
equipment.
Timing
Technological blocks are constructed simultaneously which allows Globotek to assemble the
whole complex within two month after the blocks are completed.
Efficiency
Technological blocks are produced at Globotek own factory in Tolyati which makes it very
economical since the most expensive stages are built without the involvement of outside
contractors.
2009 26
Stages of Design, Manufacture and Installation
Defining Gas Quality and Quantity
Associated gas of any quality and quantity can be processed using Globotek technology and
equipment. However the output of products and profitability of a given installation depend upon the
hydrocarbon content, temperature, pressure and other characteristics of the raw, inlet gas.
In general so called fat gas with a high content of heavier hydrocarbon gasses will give the best
profitability while components like sulphur require additional investment into equipment in order for
them to be removed from the final products.
As a rule of a thumb, gas with over 10-15 volume % content of propane and annual production of
over 5-6 mln m3 per annum would have payback period of 3 years or less. Initial assumptions can also
be made based upon oil quality, production rate analysis, oil preparation procedures and the field
development program approved by the State.
Before constructing equipment, Globotek specialists monitoring oil field production in order to
prepare a very detailed report on the abovementioned characteristics. This report guides the selection
of which modular equipment will be required and provides the basis for an exact cost of equipment
production, installation, servicing and maintenance and also profitability and payback period for the
project at hand. The cost of this monitoring program ranges from USD $100,000 to $300,000
depending upon field location, number of wells and manifolds, etc.
Design Adjustment and Equipment Production and Installation
After monitoring is completed, Globotek requires ~1.5 month to adjust the design for a particular
source of gas, to decide what particular modules will be required and to design their location on the
site.
Design adjustment, production of equipment, delivery and installation take 6-8 month for most
projects with production of associated gas of under ~50 mln m3 per annum. Installations for bigger
volumes may require additional 2 month.
As for equipment delivery, it has to be considered that certain areas of oil production have only
seasonal access for heavy cargo.
No capital construction on site is required. Modular construction is allocated on concrete platform
next to production facilities in the site.
Globotek itself and also contracted companies ready the site and install the finished units.
2009 27
Financing requirements: 50% of equipment cost is to be provided within 1-4 month of design
adjustment and equipment production. The rest is to be paid upon completion of the plant, its testing
and installation (within 8 month from the start of the project).
Performance Guarantees
At present, beyond its quality control procedures, Globotek does not offer financial guarantees as to
the performance of its units. However a combination of insurances can be arranged that comes close
to providing "performance guarantees" at an additional cost of about 0.7 - 1% of the overall capital
expenditure (capex). Discussions have been held with Rosgosstrakh and Ingosstrakh for such
insurance.
Another possibility would be to enlist a Western partner to provide such guarantees. A candidate for
this role is EuroCom Maschinen-Anlagen-Technik & Consulting GmbH (www.eurocom-
hamburg.com). EuroCom is based in Hamburg, Germany with affiliates in St Petersburg and Tver,
Russia. EuroCom is an independent international company involved in plant engineering and project
management though with little direct experience in gas processing. CAC is another potential partner
capable of providing performance guarantees (see below).
Globotek has its own service engineers who will maintain and repair its gas processing units.
Maintenance takes roughly one week per year and consists primarily of replenishing Freon and
repairing or replacing LPG compressors and pumps. There is a more extensive overhaul scheduled
every five years which again focuses on compressors and pumps. These units are expected to have a
useful life of 25 years if service is done regularly. This plant life excludes several parts such as
pumps and compressors, where the guarantee is limited by the outside manufacturer‘s guarantee and
some other precise operating conditions.
Intermediate ready product storage installation. Tanks are installed on pile foundation
2009 28
Manufacturing & Assembly Capabilities
Existing Installations
Industrial waste recycling plant
Commissioned: 2003
Raw material: non-utilised, buried industrial waste
Capacity: 1500 tones per annum
Products: polymers, non-ferrous metals
Notes: It recycles ~150 metric tons (mt) per month of waste plastics and 50 mt of waste
aluminium and 20 mt of waste anti-corrosion covers to produce 140 mt of
granulated plastics of good quality, 48 mt of aluminium powder and 18 mt of
ready-for-use anti-corrosion covering.
Mini-refinery
Client: Closed Joint Stock Company (OOO) Syndikat Oil
Location: Suzran district of Samara region of Russia
Capacity: 40,000 tones (300,000 barrels) per annum
Products: Diesel, mazut, heating oil, straight-run gasoline
Storage capacities: 800 tones of ready products
Commissioned: March 2006
Operations: From Mar-06 through Oct-09 the refinery has processed about 140,500 metric
tons (1 000,000 barrels) of crude oil
Samara Test Project
Capacity: 3 mln m3 of raw gas per year
Notes: It was built and temporally used in 2005 and 2006 from time to time to polish the
engineering and adjust technology and apply for patents
MokhtikNeft Associated Gas
Processing Complex
Subsidiary of Russneft
2009 29
.........................................................................................................................................................................
TOAZ (Tolyati Azot)
3 million tonne / year Ammonia Plant
(designed and constructed under supervision
of Alexander Lapkin)
Host TOAZ
Field Location Toyliatti
Methanol capacity 1,050,000 tonnes
Project Initiation 2000 (450 k / t)
Project upgrade 2007 (600 k / t)
Potential projects in Russia
European Russia
Samaranafta - 2 plants, one each for 30 and 40 mln m3 per year
Samaraneftegas (former Yukos - now Rossneft) - 3 plants, one each for 10, 12 and 70 mln m3
Elekneft - 700 mln m3 divided amongst 3 plants in Siberia
Kalmneft/Ingushneft/Volgademinoil – preliminary discussions on various fields
Siberia
Raw gas: 20 mln m3/year
Host: JSC ―Mokhtikneft‖ (subsidiary
of Russneft)
Field location: Mokhtikovsky field, 70 km
from Nishnevartovsk, Khanty-
Mansyisk region
Plant owner: Globotek
Process capacity: 8 000 tonnes per annum
Storage capacity: 150 m3 of finished products
Loading facility: Ramp for trucks
Project initiation: 15-Dec-2006
Commissioning: 15-Jun-2007 (natural gasoline
only)
Full Operation: 20-Sep-2007 (adds LPG unit)
2009 30
Tomskneft - 500 mln m3 divided for 4 plants in, and some more.
Rossneft and Russneft – various fields
CIS
Kazakhstan – Borankol has various fields
Turkmenistan – various fields
Other Countries / Regions
Thailand, Vietnam, Nigeria, Angola, Venezuela
Regional Funding
Globotek is now partly financed by a regional government program, (12-18 mln rubles). The
money has been put forward to evaluate the extent of raw gas flaring in the Samara region and
develop suggestions of how to minimize flaring.
Now Globotek is working to join a federal program in Russia.
Globotek‘s Management
Lapkin Alexander Nikolaevich
Science And Development Director. Honorary Petrochemist.
The author of patents and inventions. Scientific experience 3 years; industrial
experience 18 years; design experience 8 years.
Urea-formaldehyde resins and concentrates production, methanol large tonnage
production, port terminals on ammonia shipping, liquefied hydrocarbon, friable
products and tanks, wood processing, complicated reactor and technological
equipments development. Chief engineer of designed institute.
Lapkin Sergey Alexandrovich
Chief Engineer.
Scientific record is 3 years. The author of patents and inventions. Scientific
experience 3 years; industrial experience 2 years; design experience 6 years.
Industrial work record is 2 years. Condensed gases and ammonia large tonnage
production. Experimental-industrial complex director.
Project record is 6 years. Urea-formaldehyde resins and concentrates production,
methanol large tonnage production, port terminals on ammonia shipping, liquefied
hydrocarbon and methanol. Project chief engineer.
2009 31
Efimov Sergey Vyacheslavovich
Production Department Director
Industrial work record is 27 years. Oil and gas production, drilling. Normative-
technical documentation of oil companies supply. Standardization board, patent
branch, data ware deputy chief.
Project experience is 3 years. Condensed gas and gasoline production.
Nikiforov Victor Pavlovich
Analytic Department Director
Industrial work record is 39 years. Condensed gases, ammonia large tonnage and
caprolactam production. Early diagnostics of dynamic equipment and pipelines
state.
Union Reliability Laboratory Director
Project record is 3 years. Propane, butane, long distillate of a light hydrocarbon,
natural gasoline, methanol, electric power and off-centre methods production.
Scientific production association chief engineer.
Shablin Alexander Petrovich
Intrusion Department Director
Industrial work record is 32 years. Ammonia and methanol large tonnage
production, GRG processing, gaseous sulphur production. Ammonia large tonnage
production deputy chief, preparation gas and sulphur receiving director.
Project record is 3 years. Propane, butane, long distillate of a light hydrocarbon,
natural gasoline, methanol, electric power and off-centre methods production.
Scientific production association chief engineer.
Bazhutin Gregory Alexandrovich
Chief Specialist in Metrology
Industrial work record is 14 years. Aircraft building enterprise industrial control
director, checker metalworker, parcels director.
Project record is 3 years. Propane, butane, long distillate of a light hydrocarbon,
natural gasoline, methanol, electric power and off-centre methods production.
Checker parts and power supply engineer.
Reshetov Sergey Alexandrovich
Project Department Chief Engineer
Industrial work record is 5 years. Design engineer of project institute, design
department engineer of ―Kuybishevazot‖ union.
Project record is 5 years. Propane, butane, long distillate of a light hydrocarbon,
natural gasoline, methanol, electric power and off-centre methods production.
Project chief engineer.
Chernyh Elena Alexandrovna
2009 32
Project Department Director
Industrial work record is 4 years. Design engineer.
Project record is 5 years. Propane, butane, long distillate of a light hydrocarbon,
natural gasoline, methanol, electric power and off-centre methods production.
Department director.
Competitors
Competitors in Russia
Energogas Compressor www.comengas.ru
Energogas Compressor is more of a technology company which produces blocked modular
equipments on demand. The technology uses a low temperature separation gas method. The
equipment has a lifetime of 10 years and production takes 14-26 months. The cost of a 100,000
ton APG processing plant is roughly € 28 mln. The finished products are a mixture of technical
propane butane (MPBT), fuel gas, natural gasoline, dry gas, propane, butane.
AllianceExpoCom (www.aek-penza.ru) is in partnership with Energogas.
RusGasEngineering www.rusgasen.ru.
RusGasEngineering specialize in drain gas settings and natural gas condensate collection.
These include obtaining liquefied and gaseous hydrocarbons for further processing or electric
power production.
Completed projects in Russia include a complex gas preparation unit for a Nahodkinsky gas field,
a second turn condensate stabilization unit for a Tarasovsky gas condensate field and recently
they have undertaken the construction of an electric power station for the Timan-Pechorsky oil
and gas bearing province.
OOO ―Energosyntop-Engineering‖ (www.energosyntop.ru)
Energosyntop-Engineering specializes in LPG recovery modular units. A typical unit which
produces 12,400 t /year takes 7–11 months to construct, costs $ 7-10 mln and has a life time of
15-20 years. The technology can deal with a wide and varied composition of gas but the removal
of sulphur requires further refining.
The company also uses membrane separation technology to separate light hydrocarbons and
propane from petroleum, however this is particularly inefficient. Energosyntop claims of
methanol production sites are so far unsubstantiated.
CKBNM (www.ckbnm.ru)
2009 33
This is a Gazprom subsidiary which produces gas processing equipment and blocked LPG
modular units. The sizes and installation of such equipment depends on gas volume. They use the
method of low temperature separation, fractionating. The finished products are methane, natural
gasoline, propane butane, dry gas. The equipment is modular and therefore the cost of the plant
depends on gas volume (e.g. 100 000 m3 is about $6 mln, 500 000 m
3 is about $15 mln). The
product would take 1.5 -2 years in production and have a shelf life of 30 years.
Linde Gas (www.linde-gas.ru) is the subdivision of the TNK Linde Group. This company is a
major European contractor for extracting syn gas from waste using a cryogenic air separation
method. So far there is no mention of petroleum gas processing equipment but their market is
similar.
HAFI (www.hafi.ru ) is involved in power generation using petroleum gases. The company is
affiliated with a group based in Austria and Liechtenstein, whose business activities are
concentrated mainly on Central European nations (CEECs), as well as Arabic and Mediterranean
States.
HAFI's products and services include Vacuum technology, Process gas technology, Driving
technology, Environmental technology, Refrigeration technology, Conveying technology.
Chemieanlagenbau Chemnitz GmbH – CAC (http://www.cac-chem.de/) Chemnitz, is an East
German medium-sized engineering and plant construction company with representative offices in
Russia (Moscow, Tyumen, Ufa) and Kazakhstan (Almaty). They specialize in refinery and gas
engineering including gas processing plants and petrochemical plants.
Note: CAC is both a current competitor, but also a future potential partner should GRG decide to
link up with a more established company in order to provide greater quality of assurance in
Western markets and to underwrite performance guarantees, etc.
BPC Group (www.localpower.ru) in Moscow, Microturbine Capstone and Opra are also
providers of small-scale turbines driven by associated gas.
Competitors outside Russia
LPG production plants can be erected by major US/European companies like Schlumberger, Alfa
Laval and Linde, however, these tend to be large-scale and specially designed with a broad output
product mix that may extend into fertilizer, petrochemicals and plastics. At the other extreme are
Indian and Chinese companies who provide basic, but still relatively large-scale, gas processing
facilities.
A more serious competitive threat comes from young companies similar to Globotek in terms of
providing small scale, modular processing unit. Among these are:
Kryopak Inc (www.kryopak.com) belongs to US businessman George Salof. This company
specializes in modular cryogenic facilities for the production of liquefied natural gas and artificial
ice production of carbonic acid gas. The finished products are: liquefied propane butane, natural
gasoline, LNG. Their equipment is compact, with the ability to be reinstalled at other oil and
2009 34
deposits. The product can be designed to satisfy Russian standards but this increases civil and
erection works.
The equipment costs roughly $8 mln for a 33mln mcm/year processing plant. Their gas separation
sphere captures 95% of propane butane and natural gasoline. The ethane-methane mixture can be
used as fuel for heat and electric energy production or gas supply. They offer 2 types of compact
blocked modular units for processing associated gas:
- For gas fields they offer LNG equipment using a multi-component refrigerant which
liquefies the raw product.
- For oil-gas fields they use low temperature separation.
At the present Kryopak Inc has completed one project, a 130 metric ton per day LNG plant for
Beihai Xinao Gas Co. The complex was constructed by Chinese company XinAo Group.
While not directly comparable, since they are retrofitting existing plants, rather than building
completely new ones, World GTL Inc. (www.world-gtl.com/), an American based firm, has a
patent pending process to convert existing methanol plants to GTL facilities using a co-developed
catalyst. Utilizing these plants, as opposed to constructing new reactors, allows World GTL Inc to
reduce capital expenditure and significantly reduce construction time. Both of these advantages
result in quicker cash flows and higher profits.
The GTL process uses catalytic reactions to synthesize complex hydrocarbons from more basic
organic chemicals involving 3-steps. Using this technology GTL can achieve higher molecular
weight hydrocarbons ranging from LPG to paraffin waxes often controlled to peak in the diesel
range:
Step 1: After feed preparation and purification, methane undergoes steam reforming and/or partial
oxidation to form carbon monoxide and hydrogen;
Step 2: The synthesis gas is converted back into hydrocarbons using the Fischer-Tropsch (FT)
process with a cobalt (with natural gas as feed) or iron-based (with heavy feeds such as coal)
catalyst; and
Step 3: The resulting liquid products are eventually separated at a final upgrading section, which
is capable of mild hydrocracking to convert higher molecular weight waxes and lubes to LPG,
naphtha, and diesel.
World GTL‘s Trinidad Project -
Trinidad's government and World GTL Inc. are building a US$100 million (euro82 million) fuel
refinery near the Point a Pierre -
The refinery will use gas-to-liquid technology to convert natural gas into cleaner-burning diesel
products, said Arnold Corneal, a spokesman for Trinidad's state-owned oil company, Petrotrin.
The plant will be a joint venture between the government and World GTL, Ltd.
Under the agreement, the government will invest US$10 million for a 30% stake in the refinery,
while World GTL will put up the rest of the money for a 70% stake. The diesel products will be
aimed at markets in South America and the French Caribbean islands of Guadeloupe and
Martinique, where demand for high-quality diesel products is high. The refinery will be built at
2009 35
Petrotrin's main facility in central Trinidad and is expected to have a production capacity of 2,250
barrels a day and will require approximately 21mcf per day of gas feedstock. (Efficiency – 50%)
Methion (www.methion.com) offers a competing approach to small-scale associated gas
processing, but produces a different end-product, methane sulphuric Acid (MSA). The company‘s
promotes offshore technology however the product, MSA, must be shipped to a central
processing site for further refining.
The Methion MSA claims to be extremely efficient requiring far less energy than LNG systems
and methane conversion which uses the familiar Fischer-Tropsch process requiring heat,
compression, exotic metals, complex catalysts and heat integration systems. Unlike conventional
indirect methane conversion technology the Methion process successfully activates and
substitutes one hydrogen carbon bond on methane. Unlike syngas, this is a tremendous advantage
and reduces the Capital and Operating costs considerably.
The mechanism of the Methion process is very similar to conventional oxidation of hydrocarbons
in air. Combustion of hydrocarbons in oxygen is a free radical branching chain reaction initiated
by a spark to generate hydrocarbon radicals. Once the reaction starts the intermediate reactant
species becomes completely oxidized to CO2. Likewise, the Methion MSA process burns the
methane in sulphur trioxide to provide an exceptionally pure liquid product, Methane Sulfonic
Acid (MSA). MSA can be sold or further processed into transportable liquid fuels or to
petrochemicals.
Methanol Processes: Methion vs Globotek
The Methion process produces methanol via MSA (methane sulfonic acid, CH3SO3H). To make an
exact comparison would require a technological scheme including financial and energy balances,
technical and economic indices as well (unit electric power consumption kilowatt*hour/ton of
methanol, investments, finished production price, dollars/ton of methanol and payback period).
However, the main reactions of the transformation chain are as follows:
SO3+CH4 => CH3SO3H + electric power
CH3SO3H => CH3OH+SO2 + energy
SO2 + ½ O2 => SO3 + energy
According to the first formula -
There are no reactions with methane homologues transformations (С2Н6, С3Н8 etc)
Generally, waste products are sulphuric acid, carbon, alkane sulfon ethers and others (which are
genetic poisons for flora and fauna).
Part of the natural gas is spent in a gas turbine power plant or gas processing power plant with
appropriate preparation (drain, pressure raising and sulphur removal) to get electric power. The
amount of electric power required for their process is not specified.
According to the second formula -
2009 36
Common industrial methods cannot purify methane sulfacids to more than 98%. Therefore, the
methanol obtained will have a great quantity of admixtures, including sulphuric acid.
The devices that are used during the process (catalysis, thermal decomposition) and reaction
selectivity on methanol are specified.
Probably, after reaction realization follow rectification with methanol release (the residual water
will need purification from admixtures, including carcinogens)
According to the third formula -
To supply oxygen from ambient air will required that it be purified of nitrogen. This process is
labour-intensive enough, taking into account sulphuric acid presence in mixture.
There is insufficient industrial detail and too few experimental modules presented in the Methion
website to analyse their entire process. According to the information presented we can make
following conclusions:
Machines are mainly from stainless steel.
The capacity on offer is an 18m high stack is determined by 100 ton/24 hours. And at the
equipment capacity increasing in 10 times it exceeds the sizes of Globotek‘s entire methanol unit.
The advantages of Globotek‘s methodology -
Methane stem conversion is carried out parallel by continuous reactions:
- СН4+Н2О=>CO+3H2;
- СО+Н2О=>CO2+H2;
- CH4+CO2.
Methane homologues are converted to H2, СО2, СО.
Methanol synthesis occurs at ambient pressure
- СО2+3Н2=СН3ОН+Н2О
Conclusions:
Globotek has two stages instead of three with Methion method
The basic energy is obtained from gas mixtures flare, including processed gases.
There are no acids in the process. Acid equipment is not used.
There are no complex systems of purifying from acids and harmful substances
The equipment is very compact at the process carrying out under the pressure. Selectivity of
catalytic synthesis on methanol is 98%. Selectivity of catalytic reforming on raw gas is 95%.
The selectiveness is less according to the quantity of intervening stages and steps of purification
Globotek‘s closed loop process refines raw gas into methanol and water with minimum quantity
of examined mixtures.
- Methion‘s method the output is full of acids and harmful mixtures which require complex
purification.
2009 37
Methanol Processes: Conventional vs Globotek
The design of conventional methanol production equipment with 1 billion m3 capacity would take
a Western company not less than 1½ years. Manufacturing the production equipment would take
more than 1 year. Time would also be wasted for document transfer so the total project would
take at least 5 years. By contrast, use of uniform blocks allows Globotek to shorten design,
construction and production terms, since Globotek only needs to design connections for the ready
blocks, position and install them.
In the traditional approach to methanol production from sales-quality natural gas, customers and
designers proceed from the objective of maximizing gas usage. The same gas is consumed for
power supply process. Additional and complicated equipment has to be used to reach the
maximum quantity of saleable gas by deep processing. Globotek doesn‘t attempt to process the
last percentages of raw gas since the tail gas is used to run the process. Globotek doesn‘t need to
spend additional funds to prepare the gas to power the process and yet still uses it fully.
The traditional method entails a compulsory halt to production for servicing for at least one
month/year, e.g., to change the catalyst. This approach cannot be realized in the field without
halting petroleum production, resuming gas-flaring during servicing or duplicating the process
equipment for a cost premium of not less than 50%. In Globotek‘s case, the servicing problem is
fixed by the provision of an additional block (15% of increase) allowing both the servicing
process and the production process to occur uninterruptedly. In other words there is no need to
production stop for service supply.
Avoiding deep gas processing allows Globotek to make its process more compact due to the lack
of many pieces of equipment in traditional layouts. The equipment can be made modularly
because of its compactness.
The terms of equipment production are much faster than regular as we supply our request with
drafts and also produce it in series.
Modular equipment allows it to be placed in limited space, e.g., a standard absorption column
70m tall can be made in four stages of 20 m each, which is required if placed on a sea platform.
Globotek has the technology to treat low pressure and highly inert gases. Traditional circulation
procedures would accumulate inert gases in the contours of the synthesis chamber resulting in a
drop of methanol production.
Rough Estimate of Methanol Process Efficiency
Measures of efficiency are difficult to compare, since very often engineers will focus just on one
aspect of the over-all process which is typically just the reactor and not the supporting steps to
prepare the gas for conversion. In broad terms reactor efficiencies for methanol are usually ~25-
30% efficient and ~50% for the entire process.
2009 38
It is also the case that different sources of raw gas are not directly comparable, since depending
upon the sub-surface reservoir, they will contain varying amounts of wet or dry gases and other
gases, e.g., N, H2S, CO2, etc. These will have a bearing on the amount and proportion of LPG,
naphtha and methanol that can be produced at a given location.
With all of these qualifications and focusing just on the methanol process, the process economics
for the TOAZ methanol plant in Tolyati where electricity is available cheaply off the grid are as
follows:
1 mt of Methanol requires:
- 1,150 m3 of Natural Gas
- + 200 kWhrs of Electricity (or ~55 m3 of natural gas
27 for power)
- + 0.5 mt of Water
On a molecular level, 1 metric ton of methanol requires ~630m3 of methane
Methane consumed by process = ~520 m3 = 1150 – 630 m
3
Methane consumed (as electricity) to power process = ~55 m3
Rough estimate of efficiency = 1 – ({520 + 55} / {1150 + 55} ) = ~50%
27
1 kWhr = 3,410 BTU; standard natural gas has 1000 BTU/scf or 41,500 BTU/m3; assuming 30% heat rate for power
production then 55 m3 = ({200 kWhrs x 3,410 BTU}) / 30%) / (41,500 BTU/m
3)
2009 39
Supply of Liquid Petroleum Gas (LPG)
Worldwide Supply
Several events slowed the expansion of LPG supply in 2007, but growth is expected to pick up in
2008-09.
In 2006, global supplies of LPG rose to about 227 million tonnes from 199 million tonnes in 2000.
This is an increase of about 2.4%/year with supplies expected to reach about 260 million tonnes by
2010.
High LPG prices are reducing demand growth in residential and commercial sectors, especially in
unsubsidized markets in developing economies.
All of these factors will push more supplies into the petrochemical feedstock sector. A large
expansion of petrochemical capacity is under way in the Middle East, which will increase fairly
dramatically base-load demand for LPG. Global LPG supplies, however, will grow faster than base
demand, which will increase the amount of LPG available for the feedstock market
On a percentage basis, production increases have been particularly high in the Commonwealth of
Independent States (CIS), where supply increased by nearly 14% to about 12.6 million tonnes in 2006
from 6.8 million tonnes in 2000. Other regions in the same period that saw growth include the Far
East, Oceania, the Middle East, the Indian subcontinent and Latin America, each witness to a 4-5%
increase in supply.
The largest increase in supply on an absolute production basis, came from the Middle East, which
increased by 8.7 million tonnes to about 43.3 million tonnes in 2006 from a relatively large base of
34.6 million tonnes in 2000.
Thus, the Middle East accounted for almost a third of the world increase in LPG production so far in
this century. As noted previously, the CIS region had an increase of about 5.7 million tonnes. The Far
East and Latin America each had increases of about 5.1 million tonnes.
Figure 2 - Global Supply of LPG
2009 40
Source Purvin & Gertz
LPG Supply – Regions
Adapted from the Oil & Gas Journal.28
Middle East
Increased crude oil production in the Middle East during the last few years has caused an increase in
associated-gas production in the region. The corresponding increase in LPG production has freed up
some supplies for export. The largest increase in production, however, came from the gas processing
industry in the Middle East. Refineries produce only 11% of the region‘s total LPG supplies.
All of these countries continue to develop existing and new gas reserves. The continued growth in
worldwide demand for LNG will also drive expansion of gas processing in the Middle East.
North America
Despite production growth in the Middle East, North America remained the largest regional producer
of LPG in 2006. The region‘s LPG production declined, however, by 2.4 mln tonnes/year 2000-06
but North America is unlikely to lose its dominant position on the supply side for the foreseeable
future.
Production in North America had peaked in 2000 at more than 59 million tonnes but then declined to
less than 55 million tonnes by 2003. LPG production in North America is expected to reach about 58
million tonnes by the end 2007 but then decline slightly through to the end of the decade.
Africa
In Africa, LPG production rose to 16.6 million tonnes in 2006 from 14.5 million tonnes in 2000, a
growth of 2.3%/year. The net increase in production 2000-06 was driven by increases in Nigeria and
Angola.
On Africa‘s west coast, increases in crude oil production, gas processing capacity and decreases in
gas flaring since 2000 pushed Nigeria‘s LPG production up by more than 1 million tonnes.
LPG production in Nigeria is likely to increase to more than 4 million tonnes by 2010 as long as civil
unrest does not impede production. Other countries in West Africa that produce and export LPG
include Angola, the Congo, and Equatorial Guinea.
Algeria is the second largest LPG exporter after Saudi Arabia and produced about half of the total for
Africa in 2006 while Egypt produced 11% of African supply. Libya is also a fairly large producer of
LPG, and its production should reach about 1.4 million tonnes by the end of 2010.
South America
LPG production in the Caribbean and Latin America rose to more than 26 million tonnes in 2006.
Mexico, Brazil, Venezuela, and Argentina are the largest producers of LPG within the region and
together account for more than 80% of the 2006 LPG production in the region.
28
Special Report: Global markets facing adjustment to surge in LPG supply; Ron Gist, Ken Otto, Oil and Gas Journal,
Volume 105, Issue 23, 2007
2009 41
LPG production in the region is expected to rise slightly to over 30 million tonnes by 2010.
Venezuela is likely to have the largest supply growth in the future as several new projects are brought
on line. Peru, which began production from the Camisea field in 2004, should grow by almost 0.8
million tonnes as well.
Indian Subcontinent
Production on the Indian subcontinent rose to 7.9 million tonnes in 2006 from only 6.3 million tonnes
in 2000. India dominates the region‘s LPG supply, with around 95% of production. Much of the
growth has resulted from additional crude oil refining capacity that was added in the late 1990s.
Europe and CIS
Northern Europe is a large but mature producing region. LPG supplies have grown by about
1.2%/year since 2000, including a 1.1% decline in 2006. Production from the North Sea represents a
significant portion of regional production, but refineries in the region provide nearly half of the
region‘s total LPG supplies. We expect that regional supplies are expected to remain flat or slightly
reduce towards the end of the decade. Increased refinery supplies of LPG should help offset declining
North Sea supplies.
In contrast, the neighbouring CIS region is experiencing a strong increase in supply. In 2006, the CIS
region produced 12.6 million tonnes of LPG, which represents nearly a 14% /year increase since
2000. This growth occurred mainly as a result of additional gas processing in several countries. In
particular places such as Western Turmenistan have yet to commercialize associated gas.
LPG forecast production29
-
2005 2010
Kazakhstan 1,250,600 3,340,000
Turkmenistan 396,000 620,000
Azerbaijan 200,000 2,000,000
As it stands LPG production is expected to outstrip demand in the coming years. The major markets
for LPG are residential and commercial usage which will see limited growth. The large increase in
usage will come in the petrochemical industry as LPG pricing becomes more competitive relative to
other feed stocks.
Demand for LPG
Demand Forecast
LPG consumption has increased by an estimated 15% since 2000, with continued growth in demand
world-wide and particular expansion in the Asian markets.30
Reasons for increasing LPG demand:
LPG is environmentally cleaner than related fuels and carries tax incentives in many countries;
29
Regulation on the transport of dangerous goods along the TRACECA corridor. 30
Ocean Shipping Consultants Limited - LPG Trades and Shipping : Global Prospects to 2018
2009 42
LPG is seen as an alternative fuel which benefits companies associated with the Kyoto program
and carbon credits;
LPG production has increased as countries try to reduce flaring;
As society and in particular new industrial nations grow, so will the consumption of all fuels
including LPG;
LPG is increasingly used as a feedstock in the petrochemical industry.
The LPG market has always been seen as supply driven. The production of LPG has often been an
after thought by oil and gas companies due to the difficulties in harnessing the gas and the higher
costs of transport compared to liquid fuels. In the past this has lead to flaring and a worldwide
shortage of LPG, however in the next five years, global LPG supply is projected to exceed LPG
demand slightly. LPG exports should expand from 51 million tons in 2005 to 75 million tons in 2010
and 85 million tons in 2015 as companies look to exploit their LPG reserves. Therefore the LPG
market is expected to move from a supply-driven market to a demand-driven market by the end of
2010 enabling LPG to remain competitively priced.
Worldwide Consumption of LPG 31
Figure 3 - Worldwide LPG Market
31
Aygaz – Market statistics
2009 43
Figure 4 - Regional LPG Demand32
Source: Purvin & Gertz
Figure 5 - Regional LPG Consumption
Leading LPG Markets Worldwide
North America
North America is the world‘s largest consumer of LPG. The major consumer segments are
residential/commercial and the petrochemical industry. Though large market segments elsewhere, the
minor uses for LPG in North America are power production and transport. The projected increase in
supply will create lower relative prices for LPG vs other feed stocks like naphtha for the
petrochemical industry. The steady increase in the consumption of LPG has seen a rise in imports
over the past 5 years to over 5 mln mt/yr in 2005. The US and Canadian demand especially in the
petrochemical industry should easily absorb the supply of LPG worldwide as it increases, with
forecasts predicting imports to rise to over 12 mln mt/yr to meet demand.33
32
Purvin & Gertz 33
BW – LPG and ammonia shipping market
LLPP
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nn tt
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ss
0
75
150
225
300
1990
1995 2000 2002 2003 2004 2005 2010
Oceania
Africa
Middle East
FSU / E Europe
Latin America
West Europe
Asia
North America
2009 44
Japan
The LPG market in Japan now stands at 18 mln mt/yr with less than 25% coming from the domestic
production.34
LPG demand in Japan is expected to grow at an average annual rate of 1.5% in the next five years,
which makes it the fastest growing product in the Japanese market. Consumption of LPG as a
petrochemical feedstock is expected to be steady in the next five years, as prices remain
competitive.35
China
China's liquid petroleum gas shortfall is expected to hit 7.3 million tons in 2010, led by the country's
surging industrial demand. Consumption in small and middle cities in eastern and southern regions
accounts for 62 percent of the total national volume. Growing demand for LPG has been recorded in
glass, cement and pottery industries in these areas, said Bai.
Per capita LPG consumption in China hit 17.3 kg in 2006, but this was still well below the level of the
European Union and the United States.
It is predicted that consumption growth of LPG will gradually slow in the next decade, because of the
merging liquid natural gas market.
According to the development plan of the country's oil industry, domestic demand of LPG is to hit 26.2
million tons in 2010, however, supply is expected to be only 18.9 million tons.
Indonesia
Indonesia increased imports of LPG to roughly 500,000 tons in 2008 to meet domestic demand and
replace the country‘s dependence on kerosene. Therefore in total the country is expected to demand
7.5 mt/yr of LPG in 2008.36
The intention is to have every household by 2012 in Indonesia using LPG
instead of kerosene.
India
Demand for imported LPG in India is expected to remain steady going into 2009. The Minister for
Petroleum and Natural Gas claims there is need for imports of 1.73 mln mt/yr while the domestic
production will reach 8.45 mln mt/yr to meet overall demand.37
South America
Between 2001-05 the rate of consumption in South America rose by 14% year on year. Forecasts
suggest that by 2010, South American LPG production is expected to exceed 28 mln metric tons and
LPG consumption is expected to exceed 31 million metric tons.38
This would lead to overall rise in
imports as consumption out strips domestic production.
Turkey
Turkey is Europe's leading market for Liquefied Petroleum Gas (LPG) consuming 3.6 mln metric
tons in 2006. However despite the growth in the Auto LPG market, this amount was 3% below the
34
World LP Gas Association - LP Gas Center of Japan 35
SRI Consulting - http://www.sriconsulting.com/CEH/Public/Reports/380.0000/
36
Reuters UK 37
The Hindu Business Line 38 SRI Consulting – CEH Report – Propane - http://www.sriconsulting.com/CEH/Public/Reports/370.0000/
2009 45
previous year due to competition from natural gas. Even so Turkey has a huge dependence on
imported LPG which reached just under 3 mln mt/yr in 2006.
Further efforts are under way to reduce the tax disadvantage of cylinder gas against natural gas
through taxation on the basis of calorific value. This initiative is aimed at helping low income persons
in rural areas with no access to natural gas.39
Figure 6 - LPG Market in Europe (excluding Petrochemicals)
European LPG Market40
–
From 1995 to 2004, LPG demand in Central and Eastern Europe increased by 7% per year. In Poland,
the automotive fuel market for LPG (so called autogas) has exhibited extremely strong growth and
may be one of the highest growth sectors in the next ten years. In northern Europe, the United
Kingdom and Ireland are the largest consumers of LPG. Demand in northern Europe has grown at
less than 1% per year.41
Russia / CIS
The overall demand in Russia for LPG touched 6.6 mln mt/yr in 2006. Russian LPG producers,
however, are obliged to sell a certain amount of LPG at a fixed low price to the residential domestic
market. For this reason export levels will only reach roughly 1.82 mln mt/yr in 2007.
Government legislation will also allow Russian producers to sacrifice the export and residential
markets and just provide for the domestic, commercial market which provides a steady price with
lower transportation costs.42
LP Gas consumption profile in the Commonwealth of Independent States (CIS) has been flat from
2002-2006
39
Koc Energy Group Segment 40
2006 Statistical Review of Global LP Gas 41
SRI Consulting - SHE - Butane 42
LPG World – Moscow extends price controls
2009 46
Petrochemical market
Figure 7 - LPG consumption in the petrochemcial industry
The petrochemical industry is increasingly switching to LPG over naphtha as the recent increase in
supply of LPG has made it a more viable economic resource for the petrochemical industry.
The USA is the largest petrochemical industry in the world and is increasingly looking for imports of
LPG as a feedstock. The large LPG terminals on the Gulf of Mexico coast have doubled in capacity
over the last few years to take advantage of the increased supply and demand for LPG.
The Middle East is the fastest growing petrochemical market in the world and is slowly overtaking
the USA as the largest producer due to its abundant natural resources.
Autogas Market
Autogas is an environmentally preferred substitute to petrol, since it burns more fully and produces
20% less CO2. The market accounts for 8% of worldwide LPG consumption. The industry is slightly
skewed with 7 countries controlling 68% of the autogas market where the governments have
subsidized the market and given favourable tax breaks to customers.43
In countries such as Poland, autogas is the largest use of LPG in the country. The market has grown
rapidly in recent years due to the very favourable tax incentives compared to regular fuels. The fastest
growing markets are however South Korea and Turkey which have seen rapid expansion of the
autogas industry.
Demand Conclusion -
The continued growth in this industry is well documented. Asia‘s industrial sector is continuing to
grow; LPG continues to replace naphtha as a feedstock and many countries are introducing measures
43
Forecourt innovations Profile: Catalysing Automotive LPG Use: Lessons to be learnt from the world‘s leading
autogas markets
2009 47
to increase the use of autogas. With the introduction of cheaper ways to harness the gas, LPG will
remain competitive with other fuels and continue to see growth worldwide.
LPG Transportation
Conditions for Transport
LPG is a mixture of Propane and Butane. Both are gaseous at ambient temperature and pressure but
for transportation must by in liquid form. This requires change in either temperature, pressure or both
which makes transportation more expensive and dangerous than traditional fuels.
LPG usually contains a blend of the two fractions but of varying compositions. Ratios of 50:50 to
80:20 are commonly used but certain governmental regulations can restrict particular LPG
compositions.
The pressure at which LPG becomes liquid varies depending on composition and temperature; for
example, it is approximately 220 kilopascals (2.2 bar) for pure butane at 20 °C, and approximately 2.2
megapascals (22 bar) for pure propane at 55 °C.
LPG market prices are close to Diesel prices – today approx. US$ 900 per ton for delivery to
Antwerpen-Rotterdam-Amsterdam (or, CIF ARA). LPG transport costs though are roughly about 1,8-
2.5 times the price of Diesel transport costs due to different densities and different safety standards.
Thus LPG net back calculations are more sensitive to transport costs.
The limited supply of LPG has restricted infrastructure investment to major industrial markets.
Within Russia, which claims over half of all LPG reserves, no pipeline is available and the majority
of onshore transport is conducted via rail and road. This method of transport requires tankers which
must adhere to specific conditions to maintain the associated gases in liquid phase.
The proper tanker conditions must be maintained at all times during transportation since the ratio
between the volumes of the vaporized gas versus liquefied gas are typically around 250:1. LPG also
burns very easily and creates explosive blends with air. As little as 1.5 -11 % of LPG in air can create
an explosive blend. Strict guidelines for the transportation of associated gas are stated in the
International Maritime Dangerous Goods (IMDG) regulations for flammable gases (Class 2.1 goods)
wherein gas tank containers designed for transportation and storage of liquefied gases are governed
by Code UN T50.44
Tankers capacity is a function of length which comes in three sizes (25, 30, 40 feet long) and in a
variety of materials according to customer specifications. Gas tank containers must meet all
requirements for the transportation of dangerous goods in accordance to the IMDG Code, the
Agreement on Dangerous Goods by Road (ADR), and the International Transport of Dangerous
goods by Rail (RID).
44
The United Nations‘ International Maritime Organization‘s (IMO) governs the transportation of International
Maritime Dangerous Goods (IMDG).
2009 48
Table 3 - LPG Container Specifications
Length 6.058 mm
Width 2.438 mm
Height 2.591 mm
Capacity 25 000 ltr
Tare weight 8 350 kg
Max gross weight 24 000 kg
Working pressure 22.0 Bar
Test pressure 30.0 Bar
Temperature operation range - 40 + 50 C
Tank material LAS
There are three main providers of gas tank containers in Europe and the FSU. These are LLS Baltic
Container Services, Azovmash and Van Hool. Leasing companies such as Eurotainer lease LPG
containers over contractual terms ranging from 1 to 7 years or more. Eurotainer agents and depots
around Europe allow for simple delivery of LPG containers throughout the world.
Acquiring or renting tankers will be necessary to transport LPG to the railroad networks, however the
leasing of the tankers will allow for greater flexibility for GRG.
LPG handling installations could be constructed by: www.pa-salzgitter.de
LPG Rail Tank Cars (RTC‘s) could be bought from: www.azovmash.com.ua
Road Transport
This type of transport is normally used for the final delivery to the client and is sometimes used
upstream for the transportation of LPG to ports or railway depots. This method of transportation is
flexible however very expensive over long distances in comparison to other modes of transport.
The construction and operation of specialised semi-trailers for propane and butane gases in general
are subject to the European regulation ―Accord européen relatif au transport international des
marchandises Dangereuses par Route‖ (ADR) for road transports.
2009 49
A semi-trailer tanker with a 23.5-28 T load capacity will cost about € 127,000 in Western Europe. A
40 ft chassis to carry one 40ft or two 20 ft LPG containers will cost approximately €30,000 while the
cheaper 20 ft LPG containers will cost € 25,000 each, i.e. € 80,000 capital costs for the semi-trailer
with two 20 ft containers, which is less expensive than the semi-trailer tanker. In both cases, a new
truck-tractor pulling the semi-trailer would cost approximately € 90,000 in Western Europe.
The new value of a complete (LPG road transport ‗delivery‘) truck and tank will thus be in the range
of € 170,000 while a semi-trailer plus two 20 ft containers will cost about € 217,000 (Semi-trailer
Tanker).
Ukraine made rail tank cars with carrying capacity of roughly 30 -40 MT are considerably cheaper at
$60 -70,000.
Trains
Table 4 - Major Logistics Companies in Russia
Company Number of
Tank Wagons
SG-Trans 16,470
Gazpromtrans 3,414
Petrolsib 1,504
Spetstsisterny 1,021
Rail tank wagon
The construction and operation of Rail Tank Cars (RTCs) is also subject to the ―Règlement
concernant le transport International ferroviaire des marchandises Dangereuses‖ (RID) for rail
transports. They are available in Europe with capacities ranging from 85 – 120 m3 (carrying 40 – 60
tonne LPG mix). A new, 120 m3 is currently costing about € 140,000 in Europe.
Ukrainian-made RTCs for LPG with carrying capacity in the range 31-40 tonnes seem to be
significantly cheaper, in the price range of US$ 65-75,000.
Container on flat-bed rail car
Another possible way to transport LPG in an adequate way is by using tank containers. The
construction and operation of this type of equipment in general is subject to the ADR and RID
regulations as well as to the ―International Maritime Dangerous Goods Code‖ (IMDG) for combined
transports involving all kinds of shipments.
One type is a 40ft tank container which is described as a cylinder pressure tank built in a 40'
ISObeam frame, and additionally equipped with 20' contact angle according to UIC special steel E
STE 420, with sun blind fitting and 6 baffles screwed. It has a maximum payload weight approx. 23.4
tonne LPG (up to 50 m³). Such tank containers cost about € 85,000 in Western Europe.
2009 50
The alternative is a 20ft tank container described as a cylinder pressure tank built in a 20' ISO-beam
frame, with fitting for sun blind and 2 baffles screwed. Maximum payload weight is approximately
11.7 tonne LPG (25 m³). Its tare weight varies between 6.4 and 7.7 tonnes and the overall weight
limitation is 20 Ton. Its acquisition value in West-Europe is approximately € 40,000. A cheaper
alternative of a 20ft tank container is offered from Estonia, at a cost of about € 25,000. Two or even
three 20ft tank container could be carried on a flat-bed rail car. A new Russian flat-bed rail car would
cost about US$ 40,000.
Logistic companies provide an efficient service from source to storage facility. These companies are
proficient in the transport of LPG and fully aware of safety requirements. Their knowledge and access
to vital markets throughout Europe and Central Asia aid swift delivery of GRG‘s products.
SG-Trans is the largest and furthest reaching of the logistic LPG companies. It provides transportation
across all major rail networks linked to major storage units and export ports. As well as all that it
owns twelve storage stations within Russia and as far afield as Omsk and Irkutsk. SG-Trans‘ fee to
store LPG is RUR 1000 (~$40) per month per ton. On the other hand, there is also an option to sell
the LPG on to SG-Trans which will reduce the cost of logistics for the Company.
Shipping
LPG can also be shipped. LPG ships may be pressurized, fully-refrigerated, or semi-refrigerated (able
to trade from both pressure and refrigerated storages). Fully-refrigerated ships require a chiller to cool
down LPG at a load port or a re-heater to warm up LPG discharging into pressure storage. The market
has also seen a dramatic decrease in shipping rates due to a steady stream of new builds and a
stagnant demand for LPG worldwide.45
At this point in time the rate stands in the low $900,000
region for a one–month charter of a 78,000 cubic meter (cbm) ship. Depending on market conditions,
the price could be set to rise as older ships are scrapped for more efficient new build tankers.46
The largest worldwide company involved in shipping LPG is Geogas. They transport 4 million tons
on a yearly basis and have a fleet 23 specialized LPG carriers which cover the needs of any producer
all over the world.
GeoGas Fleet
Ship Size Capacity (cbm)
Large x 5 78,500
Medium x 4 22,000 – 52,000
Small x 14 3,000 – 8,000
Major overseas markets include the United States and Japan. Europe‘s largest market, Turkey,
receives the majority of LPG from across the Black Sea. Geogas47
can competitively to collect the
company‘s LPG from a given storage facility and deliver to the major markets around the world.
45
Poten and Partners – A time for LPG Ship Scrapping 46
Poten and Partners – Shipowners are upbeat on VGLC Prospects 47
www.geogas.ch/
2009 51
MC Shipping is an international shipping company which charters and manages 22 LPG vessels on
short to long term leases with capacity ranging from 3,000 – 78,000 bcm. The firm listed on the New
York stock exchange in 1989 but was recently delisted when Bear Sterns made an offer for all public
shares. The company prefers to lease the vessels as to take advantage of the volatile in the freight
markets. The company has offices in Monaco, London and Singapore to compete with the global
market.
StealthGas currently own 36 vessels for the transportation of LPG. They rank as number one in
ownership of mid-sized vessels with capacity ranging from 3,000 to 8,000 bcm.
12 Month
Time Charter
Rates
05-Oct-07 12-Oct-07 Market
Changes Monthly
T/C Rates
Daily
T/C Rates
Monthly
T/C Rates
Daily
T/C Rates
3,200 cbm S/R $320,000 $10,526 $320,000 $10,526 Steady
8,250 cbm (Eth) $645,000 $21,217 $645,000 $21,217 Steady
15,000 cbm S/R $735,000 $24,120 $735,000 $24,120 Steady
24,000 cbm $870,000 $28,618 $870,000 $28,618 Steady
28,000 cbm $880,000 $28,947 $880,000 $28,947 Steady
30,000 cbm $880,000 $28,947 $880,000 $28,947 Steady
35,000 cbm $920,000 $30,263 $920,000 $30,263 Steady
54,000 cbm $790,000 $25,987 $790,000 $25,987 Steady
57,000 cbm $950,000 $31,250 $950,000 $31,250 Steady
78,000 cbm $750,000 $25,655 $750,000 $24,655 Steady
Table 5 - Monthly and Daily LPG Shipping Prices
2009 52
Routes to Market
Figure 8- LPG Transport Routes
Russia
LPG from Russia‘s vast petroleum fields are transported via an extensive rail network. The rail
network expands through Western Europe to the Baltic Sea, East to Asia and South to shipping
terminals in the Black Sea.
Samara region LPG terminal
Major LPG ports on the Black sea are in Azov Sea at Temruk, Odessa, other Ukrainian terminals and
Batumi/Georgia. New LPG terminals are constructed at Taman – Black Sea near Novorossisk and
possibly in Primorsk/Baltic Sea which may compete with other terminals, though production levels
should rise and absorb the new capacity. Similarly excellent rail links to the Baltic Sea provide
2009 53
additional routes to market. These include Riga in Latvia, Sillamae in Estonia, Hamina in Finland,
Klaipeda for Ferry boat transport to Germany, Polish border stations, Hungarian border stations,
Ukrainian border stations and last but not least China.
At the Taman Peninsula48
the terminal is based at the Iron Horn Port. The first phase of the project is
soon to be completed for storage of up to 1,000,000 t/year of LPG with growth in phase 2 and 3.
The project will be equipped for simultaneous offloading of up to 60 rail cars into temporary,
pressurized tanks being transferred via an 1800m jetty to specialized LPG shipping tankers for
transport to markets around the world.
Figure 9 - LPG Terminal on the Taman Peninsula
Odessa is a more established terminal with access via rail link and by road. The docking terminal in
Sintez Odessa has a 13,200 t storage facility and has an annual capacity of 500,000 t. The jetty
measures 220m and has pumps to receive gas from vessels to underground storage facilities all year
round. The six pumps can work at a rate of 65 t/hr and capable of mixing the products.
Transport from Kazakhstan and Turkmenistan
Both countries have access to large reservoirs of LPG, of which the majority is exported. At present
all of Kazakhstan LPG production is transported by rail to Western Europe or to the Black Sea LPG
terminals in Odessa and Taman via Russian territory and China. Meanwhile Turkmenistan trades
almost exclusively with neighbouring countries such as Iran due to excessive transport costs. Both
routes are over capacity and therefore preparations are underway to improve LPG transportation
routes across the Caspian Sea and along to the TRACECA49
corridor (route between the Caspian Sea
and Black Sea) to provide a faster route to the western market and more competition to the Russian
rail network.
48
http://www.tamanneftegas.ru/eng/location.html 49
TRACECA is an EU sponsored programme for Transport Corridor Europe, Caucus, Central Asia
2009 54
Existing Turkmenistan LPG transport routes:
- Turkish Firm ―ALP Scan‖ is building a new terminal in the Lebap region with a 3,000MT
capacity of LPG. The terminal includes storage, processing and access to a new pipeline to the
left coast of Amudarya.
- New LPG storage and loading terminal in Serhetabad for 1,200 T
- The Caspian Sea Port of Kiyanly has a 3,000 Mt capacity for LPG. The terminal should be
complete by 2008 and hope to handle over 1,2 mln Mt/yr. The terminal can pump LPG to two
vessels simultaneously for transportation to Western Europe.
Shipping across the Caspian Sea
At present there are no LPG shipping tankers in the Caspian Sea. Instead rail ferries are used to
transport goods between Aktyau (Kazakhstan) /Turkmenbashi (Turkmenistan) and Baku. The Caspian
sea rail ferries currently transport roughly 28 containers of LPG per trip while the Russian rail ferries
can handle up to 52 containers. The cost of doing so works out at roughly $40 per tonne to cross the
Caspian Sea. Regional authorities plan to increase transit capacity with LPG shipping tankers and
larger LPG storage terminals. The route will expect to carry over 1.5 Mt per annum to the western
market.
Rail Transport across the TRACECA corridor
The rail network runs from Baku on the Caspian Sea to Batumi/Poti on the Black sea, the so called
TRACECA corridor. Between Baku (Azerbaijan) and Samtredia in Georgia the line is electrified with
2009 55
double track and operated mainly by a semi-automatic block systems. The 50-60-km section between
Samtredia and Batumi is single-track, has recently been rehabilitated and today allows speeds up to
60 km/h. The final terminals at Batumi and Poti enable transport of LPG to Samsun, Burgas/Varna,
Constantia and possibly Odessa/Ilyichevsk. Batumi is able to load vessels with up to 3,000 tonnes of
LPG and a tank capacity of 3,000 tonnes also.
LPG Terminal at Batumi
This route across the Caspian Sea and along the TRACECA corridor is in competition from the
Russian rail network feeding terminals at both Odessa and Taman. At this point in time the
infrastructure through Russia and the appropriate terminal capacity makes the Russian transport route
more economical however the route across the Caspian Sea exists and will be more effective with the
upcoming infrastructure improvements. Overall the cost of transport from Turkmenistan to the Black
sea terminals should range between US $ 185 -215 ton/ LPG. There are suggestions that the market
will demand between 1-2 mln tonnes of LPG/year in the coming years to markets throughout Europe.
Turkey
The map below displays LPG shipping terminals on the Black Sea and Mediterranean by which
imports arrive in the country. There are also major terminals in land which can be reached by rail
from the ports in the Black Sea, Mediterranean or Caspian Sea.
Aygaz50
is the largest distributor of LPG in Turkey and much of Europe. The largest import of LPG
comes from the terminal in Odessa across the Black Sea where large terminals collect LPG products
from Russia and Kazakhstan primarily.
50
Aygaz is the second largest producer of LPG in Europe and the largest in Turkey with over 1.2 million tons distributed in 2006. It also has the largest LPG storage capacity in Turkey with 146,000 m3 excluding its marine fleet. This gives the company the highest share in the country's total LPG storage capacity of 540,000 m
3
2009 56
Figure 10 - LPG Storage facilities in Turkey
Germany
The Ostee Gas Terminal is located in the Northern part of Germany. The terminal is based in Rostock
and has access to a 22,000 m3 LPG storage facility which can be reached via rail link or by the Baltic
Sea. On the Island of Rügen there is a large Ferry boat terminal for Ferry boats coming from
Klaipeda. LPG receiving terminals are under discussion to cope with the booming Autogas Market in
Germany. As per above LPG terminals in Latvia, Finland and Estonia deliver LPG throughout the
Baltic Sea.
India
The gas authrority of India (GAIL) is the largest producer of LPG in India reaching over 1 million
tonnes. They are also currently operating of over 4000 km of pipeline and of which they have the
single largest exclusive LPG pipeline of 1,250 km from Gujarat in the west of India to the New Delhi
in North India.
To summarise
- The quickest and cheapest method to transport LPG is via pipelines (however highest investment
costs) followed by large tankers, RTC‘s and smaller tankers. The most expensive is via Road
Tankers and containers but require lowest investment costs. Cost of transport schemes are also
subject to volumes.
- Transport from Oil field/plant production site will require transport via Containers or via Road
tankers to railheads; calculations for containers or Road Tankers (need loading and unloading
terminal) to be undertaken. Railhead stations allow transport to ports or receiving stations like
China, Poland, and Finland etc. Calculations to lease or buy containers or RTC‘s will be
undertaken
- Net back calculations to be undertaken to get the optimal net back product price
It must be said that transportation of LPG is more expensive than transporting petroleum but it is still
a very feasible option. There are proven facilities which enable delivery of LPG from source to end
user on a daily basis from major producers such as Russia, Kazakhstan and Turkmenistan. The
growing demand for LPG has and will enable continued widespread investment in infrastructure to
ensure supply of LPG can meet the worlds demand.
2009 57
Methanol Market
Worldwide Demand
Over the past 5 years demand for methanol has grown at roughly 3% a year. The figure is expected to
drop to 2% growth in 2008 as world consumption reaches 36 million tons. The largest area of growth
is in Asia, which now accounts for roughly 35% of world consumption, having surpassed America
which now represents only 27% of the market. Over the coming years demand for methanol is
expected to grow in the emerging markets but the more developed Western market might only see a
slight increase in sales.51
Figure 11 - World Methanol demand (% growth year on year)
Methanol is used exclusively as a feedstock for other petrochemical processes including solvents,
antifreeze and more recently for the trans-esterification of vegetable oils into biodiesel. According to
the next figure the largest derivative of methanol is formaldehyde used in adhesives, paints or plastics
followed closely by methyl tertiary-butyl ether (MTBE) production. MTBE acts as an oxygenate and
is blended with gasoline to give a cleaner burning fuel, although this is being phased out in most US
States in favour of the ethanol based tertiary-butyl ether (ETBE) which raises fewer health and
environmental concerns.
51
Metcall LLC – product info - methanol.
2009 58
Figure 12 – Chemical Derivatives of Methanol
According to the next figure the largest increase in demand will be for acetic acid. Most of this
growth will occur in Asia which has seen an increase of 1.2 million metric tons of new demand in
recent years. China accounts for the largest growth by percentage due to significant increase in
polyester production capacity to meet rapidly growing demand associated with its World Trade
Organization (WTO) participation. Additionally, acetate esters (oxygenated solvents) are growing in
China as reductions in chlorinated and hydrocarbon solvents are enacted.52
Consumption patterns suggest that the Western market for MTBE will decrease as North America
phases out MTBE as an additive to gasoline. However the growth of methanol derivatives including
MTBE in other markets should be able to counteract the expected reduction in demand in North
America.
Figure 13 - Methanol derivatives demand in the future
Worldwide Supply
Methanol supply is not demand driven and hence its price can be volatile. Over the past 10 years
many oil producers have chosen to convert their stranded natural gas (i.e., C1 – C2) into methanol as
52
Methanol Market Services Asia – Acetic Acid
2009 59
a cost effective way to transport and monetize this otherwise wasted by-product of oil production. In
the event, most methanol producers are small and independent or state owned companies. The market
has nonetheless remained buoyant because of considerable growth in demand from Asia. At the
moment there are 42 million metric tons of methanol produced a year with China and Trinidad having
the largest slice of this figure followed by the Middle East and Russia.53
As increasing number oil field owners look to sell stranded natural gas as methanol, industry capacity
should expand by an extra 24 million metric tons over the next 5 years.54
This will put pressure on
older and less efficient methanol production sites and thus create a more efficient market place.
In the short term, supply is expected to be greater than demand with the new capacity coming on-line;
however methanol demand is continuing to grow and should climb towards 47 million metric tons by
the end of the decade.
Chinese Methanol Production
China is set to become the largest producer of methanol of which 68% is generated from coal.
Chinese supply of methanol is growing at 21% year on year and reached 11.17 million tonnes at the
end of 2006, while methanol from coal reached 7.6 millions tons, a slightly larger increase of 21.6%
from the previous year.55
The greatest use of methanol is in formaldehyde production amounting to
40% followed by MTBE and Acetic acid, 6 and 7% respectfully. Demand for each methanol
derivative is robust and growing year on year but recently the fastest growing market has been the use
of methanol as a fuel. By 2011 China methanol demand is likely to exceed 11.7 million tonnes.56
Russian Methanol Production
By the end of 2006 Russia was producing 3.5 million tons per year with the largest producers shown
in the next table:
Table 6 - Largest Russian Methanol Producers
Company Production
(‗000 ton per year)
Capacity
(‗000 ton per year)
Metrafraks 1,000 + 1,000 +
Nevinnomyssky Nitrogen 450 530
Sibekinoazot 750 820
Shekinoazot 450 450 – 600
Novocherkassky 450 450
Tolyatiazot 450 800
At the moment only 75% of capacity is used. The majority of Russia‘s methanol production (1.6
million tons) is exported. Europe account for 95% of exports but with the increase in demand from
Asia, Russian exports of methanol to the East should increase.
53
Jim Jordan & Associates – World Methanol Plants 54
Chemical Market Associates Inc – 2007 World Methanol Analysis 55
Research and Markets – China Methanol Industry Report 2007 56
Methanol Institute - Milestones 2007
2009 60
Source: mmsa
Transport of Methanol in Russia
Methanol transportation is cheaper and easier than LPG. Methanol is a liquid at room temperature and
therefore does not require expensive pressurised or refrigerated containers. It is however still toxic to
living creatures and extremely miscible with water, therefore requiring the right controlled containers
for transportation.
In Russia methanol tanks are equipped with a protective cap above the hatch cover and are
transported by truck or rail under a nitrogen environment to avoid contact with oxygen. In addition
each cargo load of methanol must carry a special goods consignee who must sign off the cargo at the
beginning and end of the journey. The signature representation of methanol transportation is a yellow
and black coloured stripe (GU-27 and GU-276 – supplement N.o.4 of the present rules).
At the receiving end, methanol tanks are discharged and the tanks are cleaned to remove the odour of
methanol and any remains of water. After methanol unloading, the tanks are filled with nitrogen to
preserve control conditions for methanol transport.
Market prices
Methanol prices fluctuate seasonally, however there has been a steady rise in the price over the past 5
years. According to Methanex, the world‘s largest producer of methanol, recent methanol prices are:
Date Non–
discounted
price ($)
European
contract
price (€)
Asian
contract
price ($)
2009 61
Jan–08 832 525 720
Mar–08 632 525 525
May–08 499 295 450
Jul–08 526 295 500
Sep–08 526 295 500
Nov–08 466 395 385
The recent spike in prices is a result of production problems at the Methanex plant in Chile. Capacity
is running a quarter of expected capacity (3.5 million ton/year). The methanol market is particularly
vulnerable to plant failings and results in huge price swings during the year.57
Future Demand for Fuel Cells
At present, methanol is highly valued for its capability as a clean energy of the future. The growth of
methanol production and application in emerging markets should counteract reduced demand for
MTBE in North America, but the leading-edge application attracting the most attention now is a
methanol-reformed type fuel cell. In this application, methanol is the source of hydrogen, which,
when reacted with oxygen in a fuel cell, generates electricity. Automobiles using this power source
will have high environmental performances due to greatly reduced CO2 and any other exhaust gas
emissions. In addition, their energy efficiency will be superior to that of gasoline powered cars. In the
meanwhile, all major automobile manufacturers are researching this technology. In the foreseeable
future such advanced automobiles should be available to the general public.58
Customer Proposal
On its own the Samara region of Russia where Globotek is located has over 100 gas flares, where
more than 200 mln m3 (300 000 tons) of crude-associated gas is wasted each year. Russia in total
flares an estimated 51 billion cubic meters, Nigeria 23 bcm and the rest of the world over 70 bcm
each year. Meanwhile growing public concern and governmental awareness means that this fairly
cheap way to dispose of associated gas, i.e., flaring, is becoming increasingly unpopular and
expensive.
The alternatives to flaring are power generation, reinjection, construction of a pipeline to a gas
processing plant or construction of a captive gas plant. Each has its own capital costs and timeline.
Power generation likely requires some degree of gas cleaning and conditioning to begin with along
with connection to a power grid. Gas reinjection may require drilling of a dedicated well plus
compression equipment and (probably) its own power generators. Gas pipelines may be the simplest
option, but its cost highly dependent upon the field‘s distance from supporting infrastructure. For
example, while pipeline costs will vary by region of the world and by proximity to metropolitan
areas, in Siberia a raw-gas pipeline over level ground (not including high costs of pumping and
pressure rising equipment) in a medium climate zone, without passing rivers, hills, roads, deep-
frozen soil currently costs about RUR 10-15mn ($0.4-0.6 mln) per kilometre. Globotek competes
directly with other manufacturers of gas processing plant, but is generally thought to be 25-40%
cheaper and 6-18 months faster.
57
Methanol‘s price is spiking again by Tom Stundza (24/10/07) 58
Metcall LLC – product info - methanol.
2009 62
Deal Terms Offered to Field Owners
So, to these owners of the many oil fields that lack of nearby gas markets who would rather not divert
their capital to anything other than what increases oil production or field life results in gas being
continued to be flared, the GLOBOTEK INDUSTRIES offers a fairly compelling commercial
proposition, simply to eliminate their gas flaring in exchange for the off-take. Furthermore,
GLOBOTEK INDUSTRIES evaluates a given project at its own expense and then undertakes the
subsequent capital cost and execution risk without cost to the owner. Finally since APG typically
represents only 2.5-5% of field production by mass, the value given up by field owners will likely
seem modest.
Against this back-drop GLOBOTEK INDUSTRIES proposes to conclude long term contracts with
producers for the exclusive supply of the gases. GRG does not intend to pay for the associated gas
that it processes, arguing instead that providing a risk-free way for field owners to avoid fines should
be sufficient incentive on its own. However, despite having negative value and being small in
volume, more sophisticated owners of fields that produce particularly desirable APG (e.g., those with
high proportions of heavier hydrocarbons, C3-C7, low inert gases and low sulphur compounds) may
press for some commercial interest in the off-take. In such situations GLOBOTEK INDUSTRIES
can offer two alternative proposals. The first approach would be to offer a small share of net revenue
before GLOBOTEK INDUSTRIES‘s capital has been returned (i.e., 5% before pay-back) and a larger
share after pay-back, say 20% for a defined number of years. A second approach would be to enter
into a production sharing agreement again with a small slice to field owners before pay-back, with a
larger stake (up to 40%) after pay-back, but for the life of the field. The alternative(s) offered will, of
course, depend upon the production profile of the field.
Years for Off-Take versus Field Production Profile
It will be important that the term of off-take contracts exceed the time required to recover the capital
cost of the plant (i.e., the pay-back period) for by twice or more. For example, in the case of where
the pay back time is planned for 36 months, then the contract period to be minimum 84 months.
At issue is the fact that oil field production declines over time in a non-linear fashion, so simply
doubling the pay-back period in contracts does not necessarily guarantee an attractive investment
return. In practice each project will undergo a reservoir production review, though some general
principals on modelling production have been offered by GLOBOTEK INDUSTRIES:
A key consideration is the type of drive mechanisms – water drive is the most cautious (most of the
gas stays in the reservoir), gas-cap drive is the ‗middle‘ one, while solution gas drive gives the most
gas but is somewhat rare as the recovery factor tends to be low. For Russia one should assume a gas-
cap drive unless there is known to be an active water-flood in the field.
The second consideration concerns the plateau rare of oil production. As a rule of thumb for
‗modern‘ developments is that 50-60% of the reserves should be produced by the end of plateau.
Some of the FSU assets being looking at won‘t achieve the 50% mark (which is more a commercial
2009 63
consideration to maximize value); instead in a 30-year project they may only have had 2-3 years on
plateau and a long production ‗tail‘ where they drilled a few wells every year instead of drilling most
all of them up front. Again it‘s a matter of how ‗bullish‘ one wants to be – if you go for 50% on
plateau you‘ll get a lot of up-front gas production but it may not be representative of the case you‘re
looking at.
The next three graphs illustrate the characteristic gas production from a typical oil field with the
following properties:
Table 7 - Associated Gas Production by Reservoir Drive Mechanism
Common Reservoir Properties Drive
Mechanism
Total
Production
Years of
APG
Gas-Oil Ratio (GOR) 500 scf/bbl
Oil gravity 35 °API Water 490 mcm 13
Plateau oil rate 20,000 bopd
Plateau length 5 years Gas Cap 940 mcm 18
Total field life 25 Years
Fuel, flare etc 2 MMscfd
Solution Gas 1,245
mcm
18
Figure 14 - APG from Water Driven Field
-3
-2
-1
0
1
2
3
4
5
6
7
1 6 11 16 21 26
0
50
100
150
200
250
300
350
400
450
Gas Available (MMscfd) - LH scale
Gas-Oil Ratio (scf/bbl) - RH scale
2009 64
Figure 15 - APG from Gas Cap Driven Field
-4
-2
0
2
4
6
8
10
12
1 6 11 16 21 26
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
Gas Available (MMscfd) - LH scale
Gas-Oil Ratio (scf/bbl) - RH scale
Figure 16 - APG from Solution Gas Driven Field
-4
-2
0
2
4
6
8
10
12
14
16
1 6 11 16 21 26
0
200
400
600
800
1,000
1,200
Gas Available (MMscfd) - LH scale
Gas-Oil Ratio (scf/bbl) - RH scale
2009 65
Screening Process & Budget
Having approached or being approached by a field owner, GLOBOTEK INDUSTRIES will need to
assess the viability and investment requirements for a given field. For example, proper understanding
of a field will include assessment of:
The chemical composition of flared gases, especially to understand the percentage of C1 – C7
alkanes, since these affect overall revenue.
The contamination levels of H2S, water, N2O, H2
Logistics, such as transport of products to market, the decision to use power generation or
methanol
Additional supplies of electricity, water, etc...
While an initial interview with the owner/operator along with a desk-top review of production data
will be covered by GLOBOTEK INDUSTRIES‘s general business development budget, as a
project advances from concept to investment proposal, a range of specific expenditures will be
required.
The process to establish the final business plan and feasibility study (estimated accuracy ± 20%) for
each single project can be described and budgeted (estimated accuracy ± 20 %) as per the following
milestones which also serve as ‗drop out points‘ should the
Table 8 - Screening Budget for Project in Russia
Drop-Out
Points
Activity Cost (USD)
Initial Preparations/LOI‘s etc. 10-20,000
* Initial check based on existing gas analysis 0
* In-depth gas analysis 100-200,000
* Prefeasibility study 10-30,000
Contract signatures/negotiations 2-6,000
* Final feasibility/initial project scope 5-20,000
Western engineers/experts, if required 10-25,000
* Due diligence as required 5-50,000
Travel & Contingencies 10-50,000
Total (assuming all stages) 150-400,000
The team proposes to investigate initially 5-10 projects and decide thereafter to develop 3-5 projects
as above.
Project Structure
The legal structures may be implemented along these lines:
Equity Investors (B) execute a shareholders agreement with GLOBOTEK INDUSTRIES (A)
2009 66
Project finance investors (P) extend revolving credit line to GLOBOTEK INDUSTRIES (A)
subject to specific project approval
For each project a separate company will be established (C1….) with shareholders
GLOBOTEK INDUSTRIES (A) and third parties if necessary
C1…. concludes long-term off-take agreement with Crude Producers (D1….)
C1… concludes technical contract with Globotek (X) and possibly Western companies (Y)
C1… obtains approval from the project financiers (P) to draw against the project
C1…operates the plant and transfers products to GLOBOTEK INDUSTRIES ( (A) for
marketing
Considering the lifetime of each project to be around 10-20 years the team looks for projects that can
earn operating profits of between 50-80 % per annum on capital expenditure prior to pay back. The
team foresees the following income after pay back:
Some projects may keep their profitability at 50-80 % p.a. on long term basis. Small Russian
producers may ‗sell‘ the raw gas at low prices on long term basis
Each business plan should though foresee an increase in costs for the raw material after 5 years
(approx. 2 years after pay back) and a decrease in profitability down to 35-55 % per annum on
capital expenditure
In worst case we foresee an income of 20-45 % per annum on capital expenditure after 5 years
(approx. 2 years after pay back)
Project Team
The team which shall develop a given project shall consist of the following:
General Management from GLOBOTEK INDUSTRIES
Globotek
1 Western technical partner/advisor/controller
1 Western financial general director/controller appointed by investors
Project Company Staff
Project Time-Line
Initial project screening could take as much as 6 months in a new region or as little as one month in
European parts of Russiaa where GLOBOTEK INDUSTRIES is already active. After screening a
project would be presented to the project financiers for approval. Once received, a specific business
plan for the project would be drawn up focusing on commercial issues while an initial down-payment
for the detailed design, engineering and building of the plant would be made. Further action items
and payments are outlined in the next table.
As a live example, GLOBOTEK INDUSTRIES has an immediate opportunity to complete plants for
Samaranafta which would start the full processing of their APG by the end of 2010 at the latest till.
To do that, the following development timeline must be met:
2009 67
Mid-January: sign the development agreement. Once signed, start the feasibility studyalong with
the permitting procedures in the locations for where the plants will be built.
Mid-February: start ordering compressors in Russia and some parts in Russia and abroad; continue
with the engineering design for the project.
End-March: complete the basic project/plant design.
End-April: complete the detailed design; order all other parts; start assembly at Tolyati plant.
May – July: secure approvals for the project from state authorities and the start preparing the site for
installation.
August-September: complete site preparations; at Tolyati, complete processing units and prepare
them for shipment in blocks.
October: deliver and install plant.
November: perform initial tests and adjust production units for field conditions.
December: complete all works, commission the plant and apply for all operating licences and
permits.
In the next table along with the payments for building the processing units are shown the resulting
dividend stream:
2009 68
Table 9 - Project Time Line
Time Activity Payments Comments
1-3 months Investigate, due diligence, decide Screening budget
1 month Establish business plan Receive down-payment
2 month Commence engineering, design field
lay-outs
Begin staged payments Production
starts 8-10
mo’s after
Go-Ahead
decision
3-5 month Manufacture, assemble and erect plant
(goes on in parallel with engineering)
Plant to be fully paid
1-2 month Commission plant
Apply for operating license
20–36 mo‘s Time required for pay back Return of Capital Production
continues
long after
installation
4-15 years Lifetime of the project with planned
service/repairs 1 week per year and 1
month overhaul every 5 years
Dividends
16+ years Move plant to new oil field. Useful
life of plant is ~25-30 years if
maintained
Dividends
Example Calculation Samaranafta produces approx 1500,000 tons of Crude per annum and consequently ~45,000 tons
of potential LPG (approximately 5 % of crude production)
LPG Production Plant and Logistics Equipment Costs are estimated at US$ 10 Mio to 20 million.
Exact numbers can be given in a business plan depending inter alia on the extent of Russian
equipment versus Western equipment.
Table 10 – Sample APG Project Investment
,
Based on indications received by Globotek‘s customers, comparable Western equipment would cost a
minimum of US$ 35 mln or roughly 100% more. Becised, additional financial and time inputs will be
required to achive all licences and permissions that Globotek already has.
Project Payment Terms USD
Down-payment to developers Globotek of 30 % 5 mln
Down-payment to Western technical partners of 30 % 1 mln
Payment during construction of plant, in traches over ~6 months 9 mln
Payment on delivery of plant to Western technical partners 1.8 mln
Final payments after commissioning of the plant 1.5 mln
Guarantees and securities for the above to be established
Total costs after approx. 8-9 months
(without dedicated transportation)
16 mln
Annual Net Income from LPG sales of 25.000 tons ~10 mln
Payback time approx. ~1,5 year
2009 69
The final business plans for each project may contain proposals to secure transportation infrastructure
at estimated costs of ~10-20 % of the plant investment costs and with a pay-back of ~6 years or less.
Such additional investments will be weighted and compared to operating via rented/leased/hired
transportation schemes and the alternatives could consist of:
Purchase refrigerated tanker cars (RTC‘s) and/or
Purchase Trucks and/or
Conclude long term transport/terminal agreements and/or
Undertake participations in or erect terminals to secure terminal capacity
LPG gross income can be calculated as follows: 25,000 tons per annum x US$ 850-900 metric ton
(mt) estimated sales price minus ~$85/mt productions costs and royalties minus export taxes minus
transport costs from the production site to sales point thus ~$ 10 mln per annum (minus management
costs minus contingencies) would be the return on capital and team profit at a rate to be agreed upon
financing requirements.
2009 70
Project Financial Analysis
To estimate project returns we start by assessing the production characteristics of the oil field under
consideration. In particular, a field‘s production profile along with the amount and composition of its
raw associated gas will determine the size of the processing plant as well as the volume of end-
products to be created. Once this has been assessed, GLOBOTEK INDUSTRIES can estimate a
project‘s capital, operating and marketing costs along with the sales prices and commercial terms
proposed to the field owner in order to calculate prospective returns on investment. The following
example should help illustrate the procedure:
Defining the Base Case
We start by gathering information about a field‘s oil production and associated gas. In this case the
following are assumed:
Oil field drive mechanism: gas-cap59
Oil gravity: 35° API or 0.85 specific gravity
Gas-Oil Ratio (GOR): 500 feet3 of gas per barrel of oil produced
o Equivalent to 105 m3 of gas per ton of oil
Plateau rate of oil production: 9,750 barrels per day
o 481,000 tons/year
Plateau rate of gas production: 5.9 MMscf/day of which 4.9MMscf is available to the gas-plant;
the balance is used for reinjection or to operate the field
o 50.4 million cubic meters/year
The production profile for this field is graphed below. It is significant to note that with a field driven
by a gas-cap, the Gas Oil Ratio increases of time. This has the effect of delivering a fairly high
amount of raw gas to be processed.
-2
-1
0
1
2
3
4
5
6
1 6 11 16 21 26
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
Gas Available (MMscfd) - LH scale
GOR (scf/bbl) - RH scale
59
Gas Cap Drive: A type of reservoir-drive mechanism in which the energy for the transport and production of
reservoir fluids is provided by the expansion of gas either in the gas cap or inside the oil phase.
2009 71
Next we need to gather information about the composition of the raw, associated gas. In this case we
assume that by weight it is 67% C1 and C2 gases (i.e., methane and ethane), 19% C3-C4 (propane
and butane), 9% C5-C7 (pentane, hexane and heptane) and the remaining 5% inert gases. Based on
the stated ratios of inlet gas to final products, the model calculates the volume of outputs. (Note:
inputs to the model are in blue text with yellow background.)
Annual Input
Density
kg/Nm3
Volume
mln
Nm3/yr wt.% tons
End
Prod
Ratio
Products
Tons or
MWhr
End
Product
Associated (Raw) Gas 1.01 50.4 100% 50,900
C1-C2 content 0.74 45.9 67% 34,103 150% 51,200 Methanol
C3-C4 content 2.20 4.4 19% 9,671 80% 7,700 LPG
C5-C7 content 3.69 1.2 9% 4,581 91% 4,200 Naphtha
Inert Gases 1.00 2.5 5% 2,545
C1-C2 into Electricity bn btu 1,619 Heat rate 10,500 19.3MW 154,200 MWhrs
It is worth noting that instead of manufacturing methanol, then where access to a power grid permits
it, the C1-C2 gases can instead produce electricity, the amount of which is determined by the heat rate
or conversion efficiency of natural gas into power.
From the volumes of end-products it is possible to estimate of the capital and operating cost of the gas
processing plant. While in practice this is subject to increasing levels of engineering detail, for
purposes of the model, we use rules of thumb or heuristics, based upon prior projects. Below we
apply scenario analysis to estimate the effect of higher (and lower) capital expenditure (capex) and
operating expenditure (opex) on returns. The simplest, fastest and chepest plant to build and operate
just cleans the gas, sells the lightest fractions (C1-C2) to a local power utility, and produces only LPG
and naphtha. From the table below we observe that this will cost approximately $6m to construct
consisting of $2.9m for the LPG unit and $2.1m for the naphtha unit. Separate from the plant, but as
part of the project, we make allowance for transportation infrastructure to allow the products to be
sold. This could entail an access road, rail spur or interconnection to a power transmission line. For
the Base Case we assume this infrastructure as 15% of plant capex. While such infrastructure
sometimes already exists as part of the oil field operations, in our financial model we assume in all
cases that it must be added, so total capex comes to $6.8m ($4.4m for LPG including transport plus
$2.4 for naphtha including transport). Meanwhile operating costs for these units amount to $1.1m per
annum (see the far right-hand column).
End
Products
Capex
/Ton or
MW Capex
Transport
Infrastr
Total
Capex
Opex %
of Plant
Capex Opex
LPG 7,700 $500 $3.9m $0.6m $4.4m 17% $0.7m
Naphtha 4,200 $500 $2.1m $0.3m $2.4m 17% $0.4m
Total LPG/Naphtha $6.0m $0.9m $6.8m $1.1m
Power 154,200 $550 $10.6m $1.6m $12.2m 17% $1.6m
Total w/ Power $16.6m $2.5m $19.0m $2.8m
Methanol 51,200 $380 $19.5m $2.9m $22.4m 17% $3.5m
Total w/ Methanol $25.4m $3.8m $29.2m $4.3m
Rather than selling the methane and ethane to a local utility, if they are instead used to produce power
(i.e., the project builds its own generators), then the capex and opex increases to $19.0m and $2.8m
2009 72
respectively. Finally, if instead of generating power, a methanol unit is added to the basic gas plant,
core capex rises to $25.4m to construct or $29.2m with transportation infrastruction and costs $4.3m
per year to operate.
The next step is to calculate the operating profit per unit of sales, i.e., either tons of petroleum liquids
or megawatt hours. The key additional variables here are the market price for the finished products
and the delivery costs which include such things as rail freight, export tariffs, insurance, inspection,
handling, etc. The prices and costs in the table are compiled on the basis of sales within Russia for
methanol and power, but for export outside of Russia for LPG and naphtha. Exports of refined
petroleum products from Russia attract a substantial tariff, which is roughly 2/3rds of the tariff on
crude oil and amounts to $200/ton in this example. Finally we subtract a modest payment for the raw
gas, assumed to be r300/mcm which is roughly equal to $0.35/mcf. For simplicity we assume that the
raw gas cost is attributed to LPG and naptha rather than being spread out between all variations of
product mix. In the base case 50.4 mcm/year of raw gas is produced in the peak year which results in
$630k payment to the field owner that year. When spread across 7,700 tons of LPG and 4,200 tons of
naptha, this amounts to a $53 charge per ton of output. Finally, to be conservative in estimating
returns for the basic gas plant we attribute no value to sales of the light gases (C1-C2) although in
practice a local, municipal power generator could well pay something for them.
Price/
Unit Transp Tariff
Inspect
Insur
Total
Delivery
Net
Back /
Unit
Prod
Costs
Raw
Gas
Cost
Profit
/Unit
LPG $850 $135 $200 $24 $359 $491 $85 $53 $353
Naphtha $870 $80 $200 $19 $299 $571 $85 $53 $433
Power $40 $5 $0 $5 $35 $12 $0 $23
Methanol $325 $100 $0 $20 $120 $205 $65 $0 $140
Completing the project model with these figures shows operating profits per unit of output ranging
from $433/ton of naphtha to $23/MWhr of electricity sold. This allows a simple estimation of
profitability, namely the months required to earn back the invested capital on an operating basis. This
ranges from 14 months for the naphtha unit to 35 months when producing power, however ―Months
to Payback‖ excludes development, administrative and financing costs.
Price/Unit
Total
Delivery
Prod
Costs
Profit
/Unit
Units
Sold
Operating
Profit
Months to
Payback
LPG $850 $359 $85 $353 7,700 $2.7m 17
Naphtha $870 $299 $85 $433 4,200 $1.8m 14
Power $40 $5 $12 $23 154,200 $3.6m 35
Methanol $325 $120 $65 $140 51,200 $7.2m 32
Allowance must also be made for a royalty to the technology provider (assumed at 6% of operating
income), administrative overheads (SG&A), interest, depreciation, taxes in the like in order to solve
for free cash flow that can be used to reward stakeholders. To complete the model we scale the
project‘s cash flows in the base model to the oil field‘s decline curve rate.
The resulting model looks as follows:
2009 73
Base Case Gas-Cap Drive Yr 0 Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7
Raw Gas, MMm3/yr 19.5 38.3 42.3 46.4 50.4 54.4 46.0 38.6
Sales 7,751 8,567 9,383 10,199 11,015 9,317 7,805
OperatingIncome 3,448 3,811 4,174 4,537 4,900 4,145 3,472
GlobotekRoyalty 6% -207 -229 -250 -272 -294 -249 -208
SG&A 5% -172 -191 -209 -227 -245 -207 -174
Depreciation 8 yrs -855 -855 -855 -855 -855 -855 -855
TaxableIncome 2,214 2,537 2,860 3,183 3,506 2,833 2,235
CorporateTax 24% -531 -609 -686 -764 -841 -680 -536
NetIncome 1,682 1,928 2,173 2,419 2,665 2,153 1,699
LPG/Nafta free cash flow -$6,843 2,538 2,783 3,029 3,274 3,520 3,009 2,554
Were the same project completed with power generators with power sold at $40/MWhr, then cash
flows are projected as follows:
Base Case w/ Power Yr 0 Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7
Raw Gas, MMm3/yr 19.5 38.3 42.3 46.4 50.4 54.4 46.0 38.6
Sales 12,439 13,748 15,058 16,367 17,676 14,951 12,525
Operating Income 6,180 6,831 7,482 8,132 8,783 7,428 6,223
Globotek Royalty 6% -371 -410 -449 -488 -527 -446 -373
SG&A 5% -309 -342 -374 -407 -439 -371 -311
Depreciation 8 yrs -855 -855 -855 -855 -855 -855 -855
Taxable Income -371 -410 -449 -488 -527 -446 -373
Corporate Tax 24% -1,115 -1,254 -1,393 -1,532 -1,671 -1,381 -1,124
Net Income 3,530 3,970 4,410 4,851 5,291 4,375 3,559
w/ Power free cash flow -$19,034 4,386 4,826 5,266 5,706 6,146 5,230 4,415
The further modification is to assume that instead of selling power, the project includes a methanol
unit which is then sold at $325/ton, then cash flows and returns would be as follows:
Base Case w/ Methanol Yr 0 Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7
Raw Gas, MMm3/yr 19.5 38.3 42.3 46.4 50.4 54.4 46.0 38.6
Sales 20,398 22,545 24,692 26,839 28,986 24,517 20,539
Operating Income 8,912 9,850 10,788 11,726 12,664 10,711 8,973
Globotek Royalty 6% -207 -229 -250 -272 -294 -249 -208
SG&A 5% -172 -191 -209 -227 -245 -207 -174
Depreciation 8yrs -855 -855 -855 -855 -855 -855 -855
Taxable Income 7,677 8,575 9,473 10,371 11,270 9,400 7,736
CorporateTax 24% -1,842 -2,058 -2,274 -2,489 -2,705 -2,256 -1,857
Net Income 5,834 6,517 7,200 7,882 8,565 7,144 5,879
w/ Methanol free cflow -$29,217 6,690 7,372 8,055 8,738 9,420 7,999 6,735
Having generated the cash flows, to calculate returns we extend them for 15-year expected life of the
project. However, as decline sets accelerates in the latter years of the project (10yrs +) we assume
that gradually the production modules will be transferred to new oil fields so to maintain a similar
level of raw gas output. The resulting cash flows are next graphed them and the expected returns
calculated:
2009 74
Base Case /
Gas-Cap Capex IRR NPV10%
LPG+Naphtha $6.8m 41% $13.1m
w/ Power $19.0m 25% $16.6m
w/ Methanol $29.2m 25% $25.4m
Comparing the table of returns to the graph of cash flows for the basic gas plant (LPG/Naphtha) it‘s
worth noting that although the larger projects produce greater cash flows, they have lower internal
rates of return (25% vs 41%). This is because the required capital expenditures for both the power
and methanol are higher in relation to the product prices that are expected to be received for either
electricity or methanol. In other words, margins are higher on LPG and naphtha, so the project return
as measured by the internal rates of return (IRR) is higher.
It is true that developing just the basic gas plant is possible in GLOBOTEK INDUSTRIES GRG‘s
initial target market of European Russia. Furthermore there is an immediate opportunity to be
exploited in Russia to process the rich gases and then sell the gas to local municipalities, since
competing suppliers have spare no manufacturing capacity until 2010. This allows GLOBOTEK
INDUSTRIES to enter the market at a very strategically attractive time.
As the company grows, however, it will have to develop more complex projects that include the
lighter gases, since certain fields will be too far from an existing power generator or too remote from
a town to justify the construction of a gas pipeline. Generally the next best option will be for the
project to install its own gas generators, because the capital costs for generating power is significantly
lower than for manufacturing methanol and because the market for power is deeper. This will usually
hold whenever there is cost-effective access to a power grid. Exceptions may arise in, say, the
Russian Far East or offshore West Africa. In these cases the cost of installing a transmission line
could easily swamp the benefits of accessing an urban or industrial power market. It‘s also possible
that transmission lines might be available, but transit charges could be exorbitant or the price offered
by the incumbent utility or industrial power users may be too low to justify this option. In such cases,
it may make better commercial sense to convert the lighter gases (C1-C2) into methanol and then
send these to market by rail or ship.
2009 75
Upside Case
Keeping the same oil field characteristics (10,600 bopd of 35° API oil, etc.) we now assess an upside
case by considering lower capex (by -10%), lower transportation infrastructure cost as percentage of
plant capex (by -5% to 10%) and higher sales prices (by +10%). The key variables change as
follows:
Upside Case
Capex /t or
MW Sales Price
Trans-
poration Tariff*
LPG $450 $935 $150 $240
Naphtha $450 $957 $90 $240
Power (no export) $495 $44 $6
Methanol (no export) $342 $358 $125
The lower capex costs and higher sales prices have a positive effect on operating income
Upside Case Gas-Cap Drive
Capex Opex Sales Op Profit Pay-Back
LPG/Nafta $6.2m $0.9m $11.2m $5.0m 15
w/ Power $17.1m $2.5m $18.0m $9.3m 22
w/ Methanol $26.3m $3.9m $29.5m $13.0m 24
Upside Case /
Gas Cap Capex IRR NPV10%
LPG+Naphtha $6.2m 50% $15.6m
w/ Power $17.1m 32% $22.8m
w/ Methanol $26.3m 31% $33.3m
Here we find that IRRs rise by 6-9% while NPVs increase from $2.5m for LPG+Nafta to $7.9m for
the project with methanol.
2009 76
Downside Case
Once more using the same oil field characteristics we now assess an upside case by considering
higher capex (by +10%), higher transportation infrastructure costs (20% of plant capex) and lower
sales prices (by -10%). The key variables change as follows:
Downside Case
Capex /t or
MW Sales Price
Trans-
poration Tariff*
LPG $600 $765 $155 $160
Naphtha $600 $783 $95 $160
Power (no export) $605 $36 $7
Methanol (no export) $418 $293 $115
Unsurprisingly, both net income and free cash flow fall under this downside scenario:
Downside Case Gas-Cap Drive
Capex Opex Sales Op Profit Pay-Back
LPG/Nafta $7.5m $1.1m $9.2m $3.7m 25
w/ Power $20.9m $3.1m $14.7m $6.2m 41
w/ Methanol $32.1m $4.8m $24.2m $8.1m 47
Downside Case
/ Gas Cap Capex IRR NPV10%
LPG+Naphtha $7.5m 31% $9.1m
w/ Power $20.9m 16% $7.0m
w/ Methanol $32.1m 14% $7.0m
Free cash flow, IRRs and NPVs also fall in the Downside scenario though to a somewhat greater
magnitude than returns rose in the Upside case. More precisely, IRRs fall by 10-11% (versus rising
by 6-9%) while NPVs decrease by $4m to $18m (versus rising by $2m to $7m). The variation is
skewed because of the fixed costs associated with building and operating any plant being borne by
lower sales income.
2009 77
Water Driven Field Analysis
We now wish to examine the essentially the same gas plant, but on a field which uses a water drive.60
What is significant here is that the field produces for shorter period of time and the gas oil ratio
(GOR) is constant, as opposed to increasing as it does in the gas-cap driven field. The net result is
that there is less raw gas available to be processed. In order to achieve the same peak quantity of gas
(50.4 mln m3), the peak rate of oil production has been increased from 9,750 bopd to 16,250.
Holding all other variables constant, the previous scenarios are repeated with this reduced gas supply.
-2
-1
0
1
2
3
4
5
6
1 6 11 16 21 26
0
50
100
150
200
250
300
350
400
450
Gas Available (MMscfd) - LH scale
GOR (scf/bbl) - RH scale
Base Case Assumptions Applied to Water Driven Field
Using the same underlying capital, operating and market costs and sales prices as with the gas-cap
field, we find that operating income is higher and stable in the early years of the project compared to
the gas cap driven field.
Base Case / Water Drive Yr 0 Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7
Raw Gas, MMm3/yr 28.0 50.4 50.4 50.4 50.4 50.4 38.2 28.2
Sales 10,199 10,199 10,199 10,199 10,199 7,734 5,716
OperatingIncome 4,537 4,537 4,537 4,537 4,537 3,441 2,543
Globotek Royalty 6% -272 -272 -272 -272 -272 -206 -153
SG&A 5% -227 -227 -227 -227 -227 -172 -127
Depreciation 8yrs -855 -855 -855 -855 -855 -855 -855
Taxable Income 3,183 3,183 3,183 3,183 3,183 2,207 1,408
CorporateTax 24% -764 -764 -764 -764 -764 -530 -338
NetIncome 2,419 2,419 2,419 2,419 2,419 1,677 1,070
LPG/Nafta free cflow -$6,843 3,274 3,274 3,274 3,274 3,274 2,533 1,925
60
Water Drive: A reservoir-drive mechanism whereby the oil is driven through the reservoir by an active aquifer. As
the reservoir depletes, the water moving in from the aquifer below displaces the oil until the aquifer energy is expended
or the well eventually produces too much water to be viable.
2009 78
Returns in the Base Case are slightly better when the units are placed on a water-driven field with
field replacement. The basic gas plant (LPG+naphtha) has higher IRR (45% vs 41%) and NPV is
also higher ($13.3m vs $13.1m). The returns for the configuration with power and with methanol
also improve 27% (vs 25%) as do NPVs ($16.9m vs $16.6m and $26.0m vs $25.4m respectively).
Base Case /
Water Drive Capex IRR NPV10%
LPG+Naphtha $6.8m 45% $13.3m
w/ Power $19.0m 27% $16.9m
w/ Methanol $29.2m 27% $26.0m
Upside Case with Water Driven Field
Upside Case /
Water Drive Capex IRR NPV10%
LPG+Naphtha $6.2m 56% $15.8m
w/ Power $17.1m 35% $23.2m
w/ Methanol $26.3m 34% $34.0m
Once more we see economics improve from the Base Case to the Upside Case for water-driven fields,
with the same pattern of higher IRRs (from +3% to +6%) and slightly higher NPVs (from +$0.2m to
+$0.7m).
Downside Case with Water Driven Field
Downside Case
/ Water Drive Capex IRR NPV10%
LPG+Naphtha $7.5m 33% $9.3m
w/ Power $20.9m 17% $7.3m
w/ Methanol $32.1m 15% $7.4m
2009 79
Returns in the Downside Case are robust, but again lower with IRRs falling 15-17% and NPVs down
by $6.3-25.9m.
Solution Gas Field Analysis
Though found somewhat infrequently, solution gas driven fields61
produce the most amount of
associated gas for a given quantity of oil production. In order to specify the same size of gas-plant,
i.e., built to handle 50.4 mln m3/yr, then we lower the peak rate of oil production to 7,210 bopd from
9,750 bopd in the gas cap field and 16,250 in the water driven field. The production profile and gas-
oil ratio is depicted in the following chart:
-1
0
1
2
3
4
5
6
1 6 11 16 21 260
200
400
600
800
1,000
1,200
Gas Available (MMscfd) - LH scale
GOR (scf/bbl) - RH scale
Base Case / Gas Solution Yr 0 Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7
Raw Gas, MMm3/yr 19.6 38.0 42.5 46.7 50.5 54.0 45.4 37.7
Sales 7,690 8,604 9,448 10,222 10,926 9,191 7,629
Operating Income 3,422 3,828 4,204 4,548 4,861 4,089 3,394
Globotek Royalty 6% -205 -230 -252 -273 -292 -245 -204
SG&A 5% -171 -191 -210 -227 -243 -204 -170
Depreciation 8yrs -855 -855 -855 -855 -855 -855 -855
Taxable Income 2,190 2,552 2,886 3,192 3,471 2,784 2,166
CorporateTax 24% -526 -612 -693 -766 -833 -668 -520
Net Income 1,664 1,939 2,193 2,426 2,638 2,116 1,646
LPG/Nafta free cash flow -$6,843 2,520 2,795 3,049 3,282 3,493 2,971 2,501
Base Case economics for the core plant are almost identical with the gas-solution drive and water
drive in terms of IRR (42% vs 43%) and a NPV10% ($10.4m vs $10.6m). When configured with
power generators or a methanol unit, the IRRs are the same (21%) while NPVs are within ~$0.6m of
each other. The correspondence remains roughly the same in both the Upside and Downside Cases, so
61
Gas Solution Drive: A type of reservoir-drive system in which the energy for the transport and production of
reservoir fluids is derived from the gas dissolved in the fluid.
2009 80
there‘s no reason to make detailed commentary. Such being the case we conclude that gas-cap and
gas-solution driven fields produce similar economics.
Base Case /
Gas Solution Drive Capex IRR NPV10%
LPG+Naphtha $6.8m 41% $13.0m
w/ Power $19.0m 25% $16.4m
w/ Methanol $29.2m 25% $25.1m
Upside /
Gas Solution Drive Capex IRR NPV10%
LPG+Naphtha $6.2m 50% $15.5m
w/ Power $17.1m 32% $22.6m
w/ Methanol $26.3m 31% $33.0m
Downside /
Gas Solution Drive Capex IRR NPV10%
LPG+Naphtha $7.5m 30% $9.0m
w/ Power $20.9m 16% $6.8m
w/ Methanol $32.1m 14% $6.8m
Sensitivity Analysis
This next section examines the sensitivity of returns to changes in key variables. The tests are first
explained in the order of significance before presenting the results. Because changes will be similar
in direction and magnitude for gas plants configured to produce methanol as for power, we examine
only the methanol configuration.
Gas Specification
Here we hold the quantity of raw gas constant, but vary the amount and composition of the
underlying hydrocarbon gases. Leaner gas has more methane and ethane, but at least in this study, it
also has more inert gases. Richer gas has the reverse profile.
2009 81
Leaner Base Case Richer End Product
C1-C2 content 80% 67% 50% Methanol
C3-C4 content 5% 19% 33% LPG
C5-C7 content 3% 9% 15% Naphtha
Inerts 12% 5% 2%
Sales Prices
Here we lower or raise all product prices by a fixed percentage, 20%.
Sales Prices -20% Base Case +20%
LPG $680 $850 $1,020
Nafta $696 $870 $1,044
Power $32 $40 $48
Methanol $260 $325 $390
Raw Gas Cost
GLOBOTEK INDUSTRIES assumes that it will be able to negotiate reasonably attractive price for
the raw gas with the owners of individual oil fields, since their alternative is being penalized for
flaring.
Raw Gas Cost in rubles
per mcm
+100% Base Case -100%
R600 R300 0
Operating Expense as a percentage of Capital Expense
While detailed engineering will allow GLOBOTEK INDUSTRIES to specify operating expenses
more precisely, for purposes of modelling we have averaged the ratio of annual opex to capex for a
series of Globotek‘s plants at roughly 17% and then varied this up and down by 5%.
+5% Base Case -5%
Opex as % of Capex 22% 17% 12%
Capex for a plant configured to produce LPG/Naphtha with Methanol
Capital expenditure is one of the variables used in the scenario analysis above, but is repeated here so
as to isolate its influence on overall returns. To be consistent we have kept Opex at 17% of the
corresponding Capex in each case.
LPG+Nafta only w/ Power w/ Methanol
20% Base -20% 20% Base -20% 20% Base -20%
Capex $8.2m $6.8m $5.5m $22.8m $19.0m $15.2m $35.0m $29.2m $23.4m
Corresponding
Opex $1.2m $1.0m $0.8m $3.4m $2.8m $2.3m $5.2m $4.3m $3.5m
Corporate Tax Rate
+12% Base Case -12%
Tax Rate 36% 24% 12%
2009 82
Administrative Expense as a percentage of Operating Income
The Base Case assumption is that sales, general and administrative expenses (SG&A) vary in relation
to operating income. Once individual projects are established a more precise figure can be derived
which will consist of both a fixed (G&A) and varying component (Sales). It is also worth noting that
this variation will also serve to judge the effect of changing the technology royalty since it too is
calculated as a percentage of operating income.
+7% Base Case -7%
Opex as %-Capex 24% 17% 10%
Transportation Infrastructure Costs as a percentage of Capital Expense
Until a project undergoes a detailed review as to its distance to the nearest railway or high-tension
power line as well as the cost of building a rail spur or a power interconnect it is difficult to be precise
about the set-up costs to market the projects liquids and/or power so modelling we have assumed this
to be 15% of the capital cost of the plant itself and then varied this up and down by 5%.
+5% Base Case -5%
Transport Infrastructure
as %-Capex 20% 15% 10%
Sensitivity Table with Gas Cap Field
The next table shows both internal rates of return as well as NPV10 to the Project Funder across a
range of sensitivities in order of the most significant variable (commodity sales price) to the least
(transportation infrastructure) according the change (or delta Δ) in NPV10. For example, we note that
for the basic gas plant changing the gas specification produces the largest variance in NPV (from
$2.0m to $24.1m, or a change of $22.1m) since this determines how much product is available for
sale. It is also worth noting that the order of importance of the different stresses is not the same
when measured by IRR as for NPV10. This is because the IRR uses a different and higher discount
rate (in this case starting at 41% vs 10%) and hence factors in earlier cash flows more significantly
than later ones. Revisiting the table below we find that the largest variation in IRR is found when
changing the Sales Price (from 23% to 58%, a change of 35%).
LPG/Nafta
Gas-Cap Drive Internal Rates of Return NPV @ 10%
Change vs Base Case Δ worse BC better Δ% worse BC better Δ$
Gas Spec -/+ 28% 41% 43% 16% $2.0m $13.1m $24.1m $22.1m
Sales Prices -/+20% 23% 41% 58% 35% $4.9m $13.1m $21.4m $16.5m
Raw Gas Cost -/+100% 36% 41% 46% 11% $10.6m $13.1m $15.7m $5.1m
Capex +/-20% 33% 41% 53% 20% $11.3m $13.1m $15.0m $3.7m
Tax Rate @ 24% +/-12% 36% 41% 46% 9% $10.7m $13.1m $15.5m $4.8m
Opex @ 17% Capex +/-7% 37% 41% 45% 7% $11.4m $13.1m $14.8m $3.4m
SG&A @ 5% of Op Inc +/-4% 39% 41% 43% 4% $12.3m $13.1m $14.0m $1.7m
Transport % Capex +/-5% 39% 41% 43% 3% $12.9m $13.1m $13.4m $0.4m
2009 83
Looking below we find that for both configurations of gas plant with power or with methanol that
changes in the Sales Price have a greater influence on NPVs than does the Gas Spec. This is because
for the basic gas plant we assume that the lighter gases (methane and ethane) are sold for no net
value. By contrast, in the other configurations these gases produce a significant share of operating
income.
For example, in the Base Case with a Gas Cap Drive field with a basic plant (LPG / naphtha only)
first year sales are $7.8m, and operating income is $3.4m. When power generation is added, the C1-
C2 gases are sold as electricity to produce 60% (or $12.4m) sales and an extra 79% of operating
income (or $6.2m). When methanol is added, both sales and operating income increase by ~160%.
1st year 1
st year 1
st year Base Case
Sales %
increase
Operating
Income
%
increase
Free
Cflow
%
increase NPV
%
increase
LPG/Nafta 7,751 - 3,448 - 2,783 - $13.1m -
W/ Power 12,439 60% 6,180 79% 4,826 73% $16.6m 26%
W/ Methanol 20,398 163% 8,912 158% 7,372 165% $25.4m 94%
w/ Power
Gas-Cap Drive Internal Rates of Return NPV @ 10%
Change vs Base Case Δ worse BC better Δ% worse BC better Δ$
Sales Prices -/+20% 13% 25% 35% 22% $3.3m $16.6m $29.8m $26.5m
Gas Spec -/+ 17% 25% 31% 15% $6.1m $16.6m $26.7m $20.6m
Capex +/-20% 19% 25% 34% 15% $11.0m $16.6m $22.1m $11.1m
Tax Rate @ 24% +/-12% 21% 25% 29% 8% $11.9m $16.6m $21.3m $9.4m
Opex @ 17% Capex +/-7% 21% 25% 29% 8% $11.9m $16.6m $21.3m $9.4m
Raw Gas Cost -/+100% 23% 25% 27% 4% $14.0m $16.6m $19.1m $5.1m
SG&A @ 5% of Op Inc +/-4% 24% 25% 26% 2% $15.1m $16.6m $18.1m $3.0m
Transport % Capex +/-5% 24% 25% 26% 2% $15.9m $16.6m $17.3m $1.4m
2009 84
Beyond identifying individual exposures, what the analysis demonstrates is that business is fairly
robust across a wide range of operating conditions. When repeating the analysis for a project which
generates power or which produces methanol, the direction of changes in returns is consistent, though
the magnitudes are different.
w/ Methanol
Gas-Cap Drive Internal Rates of Return NPV @ 10%
Change vs Base Case Δ worse BC better Δ% worse BC better Δ$
Sales Prices -/+20% 11% 25% 37% 25% $2.1m $25.5m $48.8m $46.7m
Capex +/-20% 18% 25% 34% 16% $16.5m $25.5m $34.4m $17.9m
Gas Spec -/+ 20% 25% 40% 19% $16.7m $25.5m $32.3m $15.6m
Tax Rate @ 24% +/-12% 21% 25% 29% 8% $17.9m $25.5m $33.0m $15.1m
SG&A @ 5% of Op Inc +/-4% 21% 25% 25% 4% $11.3m $25.5m $26.3m $15.0m
Opex @ 17% Capex +/-7% 24% 25% 29% 5% $24.6m $25.5m $33.3m $8.7m
Raw Gas Cost -/+100% 24% 25% 26% 3% $22.9m $25.5m $28.0m $5.1m
Transport % Capex +/-5% 24% 25% 26% 2% $24.3m $25.5m $26.6m $2.2m
To conclude this financial analysis section we find the business model to be quite robust, with the
basic gas plant return IRRs in the 40% range and with both configurations adding power or methanol
production yielding in the mid-20% range while adding significantly to cash generation. The reader
should also bear in mind that GLOBOTEK INDUSTRIES is at liberty to reject any project that is not
expected to meet its return targets. Equally as the original oil field declines, GLOBOTEK
INDUSTRIES can remove and reposition its processing modules gradually to preserve its cash flow
and bolster its long-term profitability. Of course, there is risk that in repositioning the modules that
the economic terms could be worse (or maybe better) than where originally situated, but product
prices could also be higher (or lower). Such speculative forecasting, however, is beyond the scope of
this analysis. Meanwhile the processing modules will have been fully depreciated by then, yet have a
productive life of ~30 years if properly maintained and all the above analysis, which has cash flows
for only 15-years without a terminal value, should be reasonably conservative.
2009 85
Risks and Mitigations
Risk Discussion
Gas field composition
GLOBOTEK INDUSTRIES‘s success depends on finding projects which fulfill the needs of its
equipment and balance sheet. Gas composition is important as it determines the type and quantity of
end products that it can expect over the lifetime of the field.
Regulatory Changes
GLOBOTEK INDUSTRIES‘s strategy has been formulated in the light of the current regulatory
environment and with regard to future changes and likely future changes. The regulatory environment
may change in the future and such changes may have a material adverse effect on GLOBOTEK
INDUSTRIES.
Operational risks
Operational activities may involve significant risks and operational hazards and environmental,
technical and logistical difficulties. These include, inter alia, the possibility of uncontrolled
hydrocarbon emissions, fires, earthquake activity, extreme weather conditions, explosions, equipment
failure, and labour disputes. These hazards may result in delays or interruption to production, cost
overruns, substantial losses and/or exposure to substantial environmental and other liabilities.
Under Russian law, any of the Company‘s Russian subsidiaries conducting hazardous operations,
such as extraction and processing of natural gas, will be required to maintain a minimum insurance
against damages to life, health and property of third parties. Failure to obtain and maintain such
coverage may result in fines or suspension of operations for up to 90 days and could materially
adversely affect the Company‘s business, financial condition or results of operations.
Ability to develop attractive projects
Risks Mitigants
Technical failures Guarantees, Insurance, Western cooperation, Track record,
due diligence
LPG Price risks Market observations, Hedging, low break even prices giving
high buffers, price collapse risks cannot be avoided
Country risks Specific measures will vary with country of operation
Transport risks Separate transport schemes to be carefully managed and
developed as per a.m. proposals for strategic investments
Crude Production risks Portable plants; selection of partners
Globotek financial
risks
Ownership of equipment to investors; Western cooperation,
supervision, special contractual arrangements
2009 86
It is important for GLOBOTEK INDUSTRIES to secure long term projects with flaring gas
companies. Such exploitation may involve the need to obtain licenses or clearances from the relevant
authorities, which may require conditions to be satisfied and/or the exercise of discretion by such
authorities. It may, or may not, be possible for such conditions to be satisfied. Furthermore, the
decision to proceed with such long term projects may require the participation of other companies
whose interest and objectives may not be the same as those of GLOBOTEK INDUSTRIES. Such
further work may also require GLOBOTEK INDUSTRIES to meet, or commit to, financing
obligations, which it may not have anticipated or may not be able to commit to, due to lack of funds,
or inability to raise funds.
Environmental regulation
Despite its commitment to helping to reduce gas flaring and venting, future environmental legislation,
regulations and actions could cause additional expense, capital expenditures, restrictions and delays in
the activities of GLOBOTEK INDUSTRIES, the extent of which cannot be predicted. No assurance
can be given that new rules and regulations will not be enacted or that existing rules and regulations
will not be applied in a manner, which could limit or curtail its business development activities.
There may also be unforeseen environmental liabilities resulting from gas activities, which may be
costly to remedy. In particular, the acceptable level of pollution and the potential clean up costs and
obligations and liability for toxic or hazardous substances for which GLOBOTEK INDUSTRIES may
become liable as a result of its activities, may be impossible to assess against the current legal
framework and current enforcement practices of the various jurisdictions in which GLOBOTEK
INDUSTRIES operates, or in which it may operate in the future.
Marketing Risk
Marketing GLOBOTEK INDUSTRIES prospective gas liquids will be dependent on market
fluctuations and the availability of refining facilities and transportation infrastructure, including rail
tracks, road use, access to ports and shipping facilities, over which GLOBOTEK INDUSTRIES may
have limited or no control. Economic tariff rates may be increased with little or no notice and without
taking into account producer concerns. The right to export its output may depend on obtaining
licenses and quotas, the granting of which may be at the discretion of the relevant regulatory
authorities. There may be delays in obtaining such licenses and quotas, leading to the income
receivable by GLOBOTEK INDUSTRIES being adversely affected, and it is possible that, from time
to time, export licenses may be refused.
Volatility of LPG, naphtha, power and methanol prices
The demand for, and prices of GLOBOTEK INDUSTRIES‘s projects are highly dependent on a
variety of factors, including international supply and demand, weather conditions, the price and
availability of alternative fuels, actions taken by governments and international cartels, and global
economic and political developments. Geographic location and a lack of adequate infrastructure may
also result in any products being sold at a discount to world market prices. Although power prices
have been comparatively stable, international petroleum prices have fluctuated widely in recent years
and may continue to fluctuate significantly in the future.
Competition
A number of companies with competing technology may seek to establish themselves in areas in
which GLOBOTEK INDUSTRIES operates and may be allowed to bid for concessions for raw gas
from field owners thereby providing competition to GLOBOTEK INDUSTRIES. Larger companies
2009 87
in particular may have access to greater resources than GLOBOTEK INDUSTRIES, which may give
them a competitive advantage. In addition, actual or potential competitors may be strengthened
through the acquisition of additional assets and interests.
Decommissioning cost
The additional and unforeseen costs of removing the GLOBOTEK INDUSTRIES equipment from
existing oil & gas fields to new more profitable oil & gas fields. This could include additional
transport costs, licenses or environmental issues.
Taxation framework
Any change in GLOBOTEK INDUSTRIES‘s tax status or in taxation legislation could affect
GLOBOTEK INDUSTRIES‘s ability to provide returns to shareholders or alter post tax returns to
shareholders. Commentaries in this document concerning the taxation of investors are based on
current tax law and practice, which is subject to change. The taxation of an investment in
GLOBOTEK INDUSTRIES depends on the individual circumstances of investors.
The need for additional funding
The company will need to raise additional funding for the further manufacture and installation of gas
processing units, etc. Equity financing will dilute shareholder standing. Debt financing may involve
restrictions in companies financing and operative activities. In either case funding may not be
available to the company on acceptable terms. If the company is unable to secure adequate sources of
finance on acceptable terms, this will limit its long term expansion programme.
Labour
Certain of GLOBOTEK INDUSTRIES‘s operations are carried out under potentially hazardous
conditions. Whilst GLOBOTEK INDUSTRIES intends to continue to operate in accordance with
relevant health and safety regulations and requirements, GLOBOTEK INDUSTRIES remains
susceptible to the possibility that liabilities might arise as a result of accidents or other workforce-
related misfortunes, some of which may be beyond GLOBOTEK INDUSTRIES‘s control.
Payment Obligations
Under various permits, convertible bonds and other contractual arrangements that the Company either
has or may in future enter into, the Company is or may become subject to payment or other
obligations. If such obligations are not complied with when due, in addition to other remedies that
may be available to other parties, this could result in the forfeiture or forced sale of the Company‘s
assets. The Company may not have or be able to obtain financing for all such obligations as they
arise.
Litigation
Legal proceedings may arise from time to time in the course of GLOBOTEK INDUSTRIES‘s
business. There have been a number of cases where the rights and privileges of oil field service
companies have been the subject of litigation. The Directors of the Company cannot preclude that
such litigation may be brought against GLOBOTEK INDUSTRIES in future from time to time or that
it may be subject to any other form of litigation.
Uninsured Risks
GLOBOTEK INDUSTRIES, as a participant in extraction and exploration activities, may become
subject to liability for hazards that cannot be insured against or against which it may elect not to be so
insured because of high premium costs. Furthermore, GLOBOTEK INDUSTRIES may incur a
2009 88
liability to third parties (in excess of any insurance cover) arising from negative environmental impact
or other damage or injury.
Company project Licenses
The Company‘s activities will be dependent upon the grant of appropriate licenses, concessions,
leases, permits and regulatory consents which may be withdrawn or made subject to limitations.
There can be no assurance that any such authorizations will be renewed or as to the terms of any such
renewal. Properties in the jurisdictions in which the Company proposes carrying business are subject
to license requirements, which generally include, inter alia, certain financial commitments which, if
not fulfilled, could result in the suspension or ultimate forfeiture of the relevant licenses. Government
action, which could include non-renewal of licenses, may result in any income receivable by the
Company or licenses held by the Company being adversely affected. In particular, changes in the
application or interpretation of laws and/or taxation provisions in the region in which it proposes
carrying on business, could adversely affect the value of the Company‘s interests.
Retaining and attracting highly skilled personnel
GLOBOTEK INDUSTRIES‘s success depends to a significant extent on the continued services of its
core senior management team. If one or more of these individuals were unable or unwilling to
continue in his present position, GLOBOTEK INDUSTRIES‘s business would be disrupted and it
might not be able to find replacements on a timely basis or with the same level of skill and
experience. Finding and hiring any such replacements could be costly and might require the Company
to grant significant equity awards or other incentive compensation, which could adversely impact its
financial results.
Economic and Political risk
Investors in emerging markets should be aware that these markets are subject to greater risk than
more developed markets, including in some cases significant legal, economic and political risks.
Investors should also note that emerging economies such as the economy of the Russian Federation
are subject to rapid change and that the information set out herein may become outdated relatively
quickly. Generally, investment in emerging markets is only suitable for sophisticated investors who
fully appreciate the significance of the risks involved and investors are urged to consult with their
own legal and financial advisers before making an investment. This risk may adversely affect the
Company‘s financial condition, prospects or the market price of the Shares.
Social instability and calls for national security in emerging markets, coupled with difficult economic
conditions, could lead to increased support for centralized authority and a rise in nationalism. These
sentiments could lead to restrictions on foreign ownership of companies or large-scale nationalization
or expropriation of foreign-owned assets or businesses. The Governments could increase regulatory
pressures for failures or alleged failures to comply with fire, health, safety and environmental rules in
order to gain control over a company.
For example, since the dissolution of the Soviet Union, the Russian economy has experienced at
various times:
... significant declines in gross domestic product;
... hyperinflation;
... an unstable currency;
... high government debt relative to gross domestic product;
2009 89
... a weak banking system providing limited liquidity to domestic enterprises;
... high levels of loss-making enterprises that continued to operate due to the lack of effective
bankruptcy proceedings;
... significant use of barter transactions and illiquid promissory notes to settle commercial
transactions;
... widespread tax evasion;
... growth of a black and grey market economy;
... pervasive capital flight;
... high levels of corruption and the penetration of organised crime into the economy;
... significant increases in unemployment and underemployment; and
... the impoverishment of a large portion of the population.
The regulation and supervision of the securities market, financial intermediaries and issuers are
considerably less developed in countries such as Russia than in the United States and Western
Europe. Securities laws, including those relating to corporate governance, disclosure and reporting
requirements, have only recently been adopted, whereas laws relating to anti-fraud safeguards, insider
trading restrictions and fiduciary duties are rudimentary.
Exposure to currency fluctuations
As an international gas processing company, most of the GLOBOTEK INDUSTRIES‘s revenues and
a significant portion of its costs will be denominated in U.S. dollars or Euros. In addition, as
commodity prices are denominated in U.S. dollars or Euros, most of the GLOBOTEK
INDUSTRIES‘s income will be received in U.S. dollars and Euros and GLOBOTEK INDUSTRIES
is therefore exposed to volatility in exchange rates. As a result, the GLOBOTEK INDUSTRIES‘s
revenue is subject to exchange rate movements. The company intends to hedge currencies to reduce
exposure to currency fluctuations.
Reserve and resource estimates
Return of investment is dependent on the successful gas production from the gas field projects. The
group could experience revenue decrease due to overestimation of gas reserves or higher capital and
operating costs. Increase cost or fluctuations of gas prices could make some potential gas fields
uneconomical for GLOBOTEK INDUSTRIES production technology.
Technology shortfall
The processing units from our partners, Globotek, could suffer from problems of delay or
deployment. It also could face competing technology which is more efficient at processing associated
gas. All of these problems could impact the amount of fuels, power and/or methanol produced by
GLOBOTEK INDUSTRIES in the long term.
Company‘s internal financial controls
Whilst the Company intends to install modern management information systems and financial
controls necessary to manage its business and financial reporting effectively, such systems and
controls may not yet be comparable to those of the Company‘s competitors and any significant
deficiencies or material weaknesses in the Company‘s internal controls or in the Company‘s
International Financial Reporting Standards consolidated financial statements not being reported on a
timely basis could have a material adverse effect on the Company‘s business, financial condition,
2009 90
results of operations, future prospects and the value of its Shares. This may adversely affect the
Company‘s financial condition.
2009 91
Appendices
General information about LPG
Definition and characteristics of LPG
Liquefied petroleum gas (also called liquefied petroleum gas, liquid petroleum gas, LPG, LP Gas, or
auto gas) is a mixture of hydrocarbon gases. They liquefy at moderate pressures, readily vaporizing
upon release of pressure.
Varieties of LPG bought and sold include mixes that are primarily propane, mixes that are primarily
butane, and mixes including both propane and butane, depending on the season—in winter more
propane, in summer more butane. Propylene and butylenes are usually also present in small
concentration. A powerful odorant, ethanethiol, is added so that leaks can be detected easily.
At normal temperatures and pressures, LPG will evaporate. Because of this, LPG is supplied in
pressurized steel bottles, tanks, containers, vessels, pipelines. In order to allow for thermal expansion
they are filled to between 80% and 85% of their capacity. The ratio between the volumes of the
vaporised gas and the liquefied gas varies depending on composition, pressure and temperature, but is
typically around 250:1. The pressure at which LPG becomes liquid, called its vapour pressure,
likewise varies depending on composition and temperature; for example, it is approximately 220
kilopascals (2.2 bar) for pure butane at 20 °C, and approximately 2.2 megapascals (22 bar) for pure
propane at 55 °C. Propane gas is heavier than air, and thus will flow along floors and tend to settle in
low spots, such as basements. This should be kept in mind to avoid accidental ignition or suffocation
hazards.
While butane and propane are different chemical compounds, their properties are similar enough to be
useful in mixtures. Butane and Propane are both saturated hydrocarbons. They do not react with
other. Butane is less volatile and boils at 0.6 deg C. Propane is more volatile and boils at - 42 deg C.
Both products are liquids at atmospheric pressure when cooled to temperatures lower than their
boiling points. Vaporization is rapid at temperatures above the boiling points. The calorific (heat)
values of both are almost equal. Both are thus mixed together to attain the vapour pressure that is
required by the end user and depending on the ambient conditions. If the ambient temperature is very
low propane is preferred to achieve higher vapour pressure at the given temperature.
Main characteristics of LPG are as follows:
It is colourless and cannot be seen
It is odourless. Hence LPG is odorized by adding an odorant prior to supply to the user
It is slightly heavier than air and hence if there is a leak it flows to lower lying areas.
In liquid form, its density is half that of water and hence it floats initially before it is vaporized.
It is non-toxic but can cause asphyxiation in very high concentrations in air.
Application and advantages of LPG
LPG is increasingly replacing chlorofluorocarbons as an aerosol propellant and a refrigerant to reduce
damage to the ozone layer. The clean burning properties and portability of LPG provide a substitute
2009 92
for traditional fuels such as wood, coal, and other organic matter. This provides a solution to de-
forestation and the reduction of particulate matter in the atmosphere (haze), caused by burning the
traditional fuels. LPG is used as a fuel for domestic (cooking), industrial, horticultural, agricultural,
heating and drying processes. It is further used as an automotive fuel or as a propellant for aerosols, in
addition to other specialist applications. LPG can also be used to provide lighting through the use of
pressure lanterns.
The main advantages of LPG are as follows:
Because of its relatively fewer components, it is easy to achieve the correct fuel to air mix ratio
that allows the complete combustion of the product. This gives LPG its clean burning
characteristics.
Both Propane and Butane are easily liquefied and stored in pressure containers. These properties
make the fuel highly portable, and hence, can be easily transported in cylinders or tanks to end-
users.
LPG is a good substitute for petrol in spark ignition engines. Its clean burning properties, in a
properly tuned engine, give reduced exhaust emissions, extended lubricant and spark plug life.
Table: LPG compared to petrol and diesel
Compared to petrol Compared to diesel
- 75 % less carbon monoxide - 60% less carbon monoxide
- 40% less oxides of nitrogen - 90% less oxides of nitrogen
- 87% less ozone forming potential - 70% less ozone forming potential
- 85% less hydro carbons - 90% less particulates
- 10% less carbon dioxide
Table 11 - Environmental differences between LPG, diesel and petrol
Formation and production
LPG comes from two sources. It can be obtained from the refining of crude oil. Simple refining in a
crude distillation tower will yield about two percent LPG. When produced this way it is generally in
pressurized form. LPG is also extracted from natural gas or crude oil streams coming from
underground reservoirs. It is formed naturally in oil and gas fields and is pumped out from the wells
mixed in with other fuels, typically about 0.2 to 0.4 percent of the produced crude oil but much higher
proportion is possible. At the oil and gas facilities, butane and propane gases are separated from the
heavier fuel and stored in purpose-built storages. About 60% of LPG in the world today is produced
this way whereas about 40% of LPG is extracted from refining of crude oil.
The characteristics made LPG a late developer in the hydrocarbon business. The first commercial
production had to wait until the 1920‘s, the first international trade until the 1950‘s. Seaborne trade in
LPG was less than 1 million tons in 1960, reached 17 million tons by 1980, and was in excess of 47
million tons by the year 2000
Differences between LPG, LNG and CNG
Liquid petroleum gas (LPG, and sometimes called propane) is often confused with LNG and vice
versa. They are not the same and the differences are significant. LPG has a higher calorific value (94
2009 93
MJ/m³) than natural gas (methane) (38 MJ/m³), which means that LPG can not simply be substituted
for natural gas.
Liquefied natural gas or LNG is natural gas consisting primarily of methane (CH4, typically, at least
90%), the shortest and lightest hydrocarbon molecule but may also contain ethane, propane and
heavier hydrocarbons. It has been processed to remove impurities and heavy hydrocarbons and then
condensed into a liquid at atmospheric pressure by cooling it to approximately -163 degrees Celsius.
LNG is transported by specially designed vessels and stored in specially designed tanks. LNG is
about 1/600th the volume of natural gas at standard temperature and pressure (STP), making it much
more cost-efficient to transport over long distances where pipelines do not exist. LNG is odourless,
colourless, non-corrosive, and non-toxic. When vaporized it burns only in concentrations of 5% to
15% when mixed with air. Neither LNG, nor its vapour, can explode in an unconfined environment.
Compressed natural gas (CNG) is natural gas pressurized and stored in welding bottle-like tanks at
pressures up to 3,600 psig. Typically, it is same composition of the local "pipeline" gas, with some of
the water removed. CNG and LNG are both delivered to the engines as low pressure vapour (ounces
to 300 psig). CNG is often misrepresented as the only form natural gas can be used as vehicle fuel.
LNG can be used to make CNG. This process requires much less capital intensive equipment and less
operating and maintenance costs.
2009 94
Globotek Licenses
LICENSE
D 930519
Registration number From the 1 of October 2007
Federal agency for construction and housing and communal services allows the Licensee to construct
buildings and projects of level I and II responsibility according to the State standard
To JSC
"Globotek"
ОГРН 1056325049000
446073, Samarskaya region, Syzransky district, Varlamovo vill, Sovetskaya street, 14
The license was given for construction and housing by the Communal Services Federal agency
From the 1 of October 2007 N.o. 293
The license is valid in Russian Federation territory
ГC-4-63-02-26-0-6325037621-011077-1
Construction of buildings with level II responsibility
Processing of the project documentation on
construction of buildings and it complexes - General plans and transportation
General plans (schemes) for buildings and territory Schemes (projects) for the accomplishment of
territory for buildings
Planting of trees and gardens Territory engineering preparation
Architectural decisions Architectural part (layouts, facades)
Structural decisions Foundations
Fenced constructions Technological decisions
Industrial buildings and its complexes Chemical and petrochemical enterprises
Setting up output production of nitrogen industry Setting up artificial rubber production
Setting up the main organic synthesis production Gas scrubbing settings
Industrial enterprise constructions Transportation objects and their complexes
Enterprise of main pipelines Construction for pipelines
Storage for oil and gas products Engineering equipment, nets and systems
Heating, ventilation and conditioning Water supply and sewerage system
Gas supply –
Cold Power supply, using up to 1 kilowatt
Preservation of the Organization‘s environment and
working conditions
Implementation of General designer functions for
project buildings, constructions and its complexes
For the following types of buildings, constructions
and its complexes ^
Residential construction and its complexes:
Building height - up to 4 storeys high Public building and constructions
For construction in the territory with engineering
geological conditions
Level II category of complexity
2009 95
LICENSE
D 935404
Registration number from the 8 of October 2007
ГС-4-63-02-27-0-6325037621-011076-1
Federal agency for Construction and Housing and Communal Services allows the licensee to construct
buildings and projects of level I and II responsibility according to the State standard
To JSC
"Globotek"
ОГРН 1056325049000
446073, Samarskaya region Syzransky district, Verlamovo vill, Sovetskaya street, 14
The license was given for construction and housing by the Communal Services Federal agency
Erection of technological facilities – Compressor machines
Industrial Stoves Electro technical settings
Boiler settings Automated systems
Chemical and petrochemical industry
enterprises.
Chemical and petrochemical machinery
construction enterprises
Start-adjusting works – Compressor machines, pumps and ventilators
Industrial stoves Boiler settings and support equipment
Refrigerating and compressor settings Equipment for air separation and cryogenic
technology settings
Chemical and petrochemical enterprises
equipment
Chemical and petrochemical machinery
construction equipment to fulfil the customer‘s
order
Initial date for receiving construction objects
projection Preparation for assignment –
Technical supply at project stage Documents required for construction and
reconstruction
Supply of Construction territory Organization of Construction management
Technical supervision -
Construction of buildings up to 40 m in height is
allowed
Sanitary technical works, Engineering networks
and communications -
Isolation valve settings -
Heat net settings with heat bearer temperatures
up to 115 C°
Heat net settings with heat bearer temperatures
more than 115 C°
2009 96
Water-supply nets setting, including polymeric
materials
Sewer net setting, including polymeric materials
Inner engineering systems and equipments
setting works
Ventilation and heating, air conditioning systems
setting
Heat systems setting with heat bearer
temperatures up to 115 C°, including polymeric
materials.
Heating net setting with heat bearer temperatures
more than 115 C°
Sanitary technical equipment settings. Calculation and control equipments setting
Special works -
Metal construction assembling Buildings construction Technological metal
construction
Construction, technological equipments and
pipelines
Corrosion protection
Pipelines and equipment heat insulation, working
at the temperature no more than 115 C° Pipelines
and equipment heat insulation, working at the
temperature higher than 115 C° Refrigerating
isolation
Transport construction Trunk-roads
Streets and roads for apartment blocks
Power supply net setting, up to 1 kilowatt Inner engineering systems and equipments setting
works
Gas systems and equipment setting Technological pipelines setting
Power supply setting up to 1000 v Electric light setting
Communications, radio and TV setting
Works concerned with high danger of industrial
productions
Objects of gas supply facility
Outside gas pipelines of cities, villages and
settlements
Gas regulator stations and settings
Gas pipelines and gas equipments of industrial,
agricultural and other enterprises Gas filling stations
Fixed motor gas filling stations Reserve and group settings of LG
Chemical, oil and gas processing, pulp and paper
and other fire-hazardous objects
Steam-boilers, pipelines for steam, working
under more than 0.7 kgc/cm2 of pressure
Hot water boilers and pipelines with a heating
temperature of more than 115 C°
Construction of buildings with level II
responsibility
General construction works -
Geodesic works in construction squares Geodesic control of buildings geometric
parameters
Executive geodesic shooting Preliminary works
Territory clearing and its preparation for
construction
Construction teardown
Temporary roads and network constructions Rail track lying
Earthworks Stonework
2009 97
Concrete and reinforced concrete construction
setting
Rebar works
Monolithic concrete and reinforced concrete
construction setting
Wood construction assembling
Metal construction Defend the construction from extrusion slabs
Defend the walls of the construction from glass
blocs Isolation works
Isolation setting from roll materials, polymeric
rolls and metal plates Territory accomplishment
Footpaths and squares setting Open sport facilities setting
Planting of trees and gardens Implementation of general contractor functions
Finishing works Facade works execution
Stuccoworks execution Decorative finishing works execution
Glass works execution Face works execution
Sanitary technical works, Engineering networks
and communications - Isolation valve settings -
Heat net settings with heat bearer temperatures
up to 115 C°
Heat net settings with heat bearer temperatures
more than 115 C°
Water-supply nets setting, including polymeric
materials
Sewer net setting, including polymeric materials
Inner engineering systems and equipments
setting works
Ventilation and heating, air conditioning systems
setting
Heat systems setting with heat bearer
temperatures up to 115 C°, including polymeric
materials.
Heating net setting with heat bearer temperatures
more than 115 C°
Sanitary technical equipment settings. Calculation and control equipments setting
Special works -
Metal construction assembling Buildings construction Technological metal
construction
Construction, technological equipments and
pipelines
Corrosion protection
Pipelines and equipment heat insulation, working
at the temperature no more than 115 C° Pipelines
and equipment heat insulation, working at the
temperature higher than 115 C° Refrigerating
isolation
Transport construction Trunk-roads
Streets and roads for apartment blocks
Power supply net setting, up to 1 kilowatt Inner engineering systems and equipments
setting works
Gas systems and equipment setting Technological pipelines setting
Power supply setting up to 1000 v Electric light setting
Communications, radio and TV setting
Works concerned with high danger of industrial Objects of gas supply facility
2009 98
productions
Outside gas pipelines of cities, villages and
settlements
Gas regulator stations and settings
Gas pipelines and gas equipments of industrial,
agricultural and other enterprises Gas filling stations
Fixed motor gas filling stations Reserve and group settings of LG
Chemical, oil and gas processing, pulp and paper
and other fire-hazardous objects
Steam-boilers, pipelines for steam, working
under more than 0.7 kgc/cm2 of pressure
Hot water boilers and pipelines with a heating
temperature of more than 115 C°
Erection of technological facilities – Compressor machines
Industrial Stoves Electro technical settings
Boiler settings Automated systems
Chemical and petrochemical industry
enterprises.
Chemical and petrochemical machinery
construction enterprises
Start-adjusting works – Compressor machines, pumps and ventilators
Industrial stoves Boiler settings and support equipment
Refrigerating and compressor settings Equipment for air separation and cryogenic
technology settings
Chemical and petrochemical enterprises
equipment
Chemical and petrochemical machinery
construction equipment to fulfil the customer‘s
order
Initial date for receiving construction objects
projection Preparation for assignment -
Technical supply at project stage Documents required for construction and
reconstruction
Supply of Construction territory Organization of Construction management
Technical supervision -
Construction of buildings up to 40 m in height is
allowed
2009 99
Globotek‘s Patents
PATENT FOR INVENTION
N.o 2275562
Technology for raw gas separation
Patent holders: Lapkin Alexander Nilolaevich (RU), Lapkin Sergey Aleksandrovich (RU).
Authors: Lapkin Sergey Aleksandrovich (RU), Lapkin Alexander Nilolaevich (RU).
Request: N.o. 2004113578
Invention priority: April, 30 2004
Registered in State Register of
Inventions in Russian Federation in April, 27 2006
Patent expired date is April, 30 2024
The Chief of the federal service on intellectual property, patents and trade marks is B.P. Simonov.
2009 100
Patent description (gas separation)
This invention is related to the oil and gas industry and primarily separates natural and associated
petroleum gas into their singular constituents. APG or natural gas is obtained from gas deposits, gas
condensate or oil and is comprised of a mixture of carbon chains with methane being the largest
contributor. Usually, natural gas is comprised of at least 95 % methane and a few other light
hydrocarbons. The byproduct of the mixture contains mainly nitrogen and carbonic acid gas. The
2009 101
exact composition varies in broad limits and can contain different contaminations, including hydrogen
sulfide and mercury.
APG or natural gas can be poor or rich in saturated hydrocarbons. Poor gas implies there are fewer
heavier hydrocarbons compared with rich gas. Associated gas from oil deposits will have a higher
density of heavy hydrocarbons, for instance, propane, butane, pentane including gaseous components
hydrogen, nitrogen, carbon dioxide but less ethane and methane. Propane and other heavy components
can easily be recovered from the natural gas, gas of oil and gas enterprises, associated gas of oil
deposits and also natural gas of unstable composition.
The Cryogenic process is often used to separate propane and more heavy hydrocarbons from the
natural gas inflow. This standard practice is used for capture and recovery of ethane and propane
however; present processes are directed more at the recovery of ethane and methane. Often these gases
are sent via pipeline to large gas processing plants however sometimes such processes are
uneconomical if the gas field is small (1mln – 50 mln nm3/year) or hard to reach. In this case wet
associated gas can be partly processed (30-60%) into useful products.
It has therefore been necessary to find an alternative method of gas processing which will allow
recovery of propane and heavier hydrocarbons from APG and natural gas.
The liquidation of such gases can be made by a cooling method using a counter flow heat exchange
interaction with gaseous coolant instead of liquid coolants. The coolant passes through the cooling
cycle which includes at least one compressor stage and one stage of broadening.
This method initially requires the gas to be purified from carbonic acid gas, water, sulphur
combinations and heavier hydrocarbons. Then further gas cooling by an outer coolant at -146 C° to
obtain a liquid end gas. The pressure of the initial gas composition is about 5.5 MPa and it is
necessary to compress coolant in the bloc of a multi-stepped compressor up to a 5.6 MPa pressure
(Patent RF N.o.2141084, MPK 6 F 25 J 1/02, 1999).
This method is however limited as it is does not separate the gas into fractions and requires high
pressure to be maintained in both the pipeline of initial gas and outer coolant.
The patents for the above mentioned method involve settings for natural gas liquation which include
heat exchangers, compressor instruments (Patent RF N.o.2141084, MPK 6 F 25 J 1/02, 1999).
The disadvantage of this procedure is that compressor units require constant care and many are
required for outer coolant compression.
There are also methods of purifying associated petroleum and natural gases from hydrogen sulphide
and carbon dioxide content. One acid separation method puts the raw gas under excess pressure and is
cooled to -58 C° temperature. The products are divided by a gravity field (Patent RF N.o.2116698,
MPK 7 F 25 J 3/08, 2003).
The method is flawed as liquids are often insoluble at -58 C° and gravity separation is a very time
consuming method which requires low speeds of movement and the lack of interference from the
surrounding environment. This method requires an expensive large single capacity vessel and
moreover the given method does not solve the problem of separating gas liquid fractions.
A more complete method of gas separation allows for a stepped cooling system. This method allows
the gas to be cooled in one or several heat exchangers with the help of cold streams. The cooled gas
fractions are broadened further by a low pressure distillation column where the raw gas is finally
separated into their desired fractions (Patent RF N.o.2047061, MPK 6 F 25 J 3/02, 1995).
In this method the gas, outer coolant and residual gas pipelines are kept under the same pressure
conditions. Moreover, this method can not be used for the complete separation of isobutane, butane
and propane.
Another gas separation process replaces the forward flow line of an initial gas machine with a
consecutive plug in the regenerative heat exchange-condenser to repeat the regenerative heat
exchanger process (Patent of Russian Federation N.o. 2047061, MPK 6 F 25 J 3/02, 1995).
2009 102
This method requires a large amount of compressors, which are not mobile and are only used for
large processing industrial complexes. It is necessary to supply gas via pipelines to use the equipment
in full operation which causes additional expense.
The latest invention was able to separate out net gas fractions from the raw gas at lower pressures
than the competition and reduce costs using a modular and movable equipment system.
The technology in question in this article can achieve separation of each gas fraction at a lower
cost. Firstly the initial gas is maintained at a lower pressure (0.002-0.004 MPa (0.02-2.4 kg/cm2)).
Furthermore, liquid fractions are separated from the gas phase after each cooling step which increases
the end product quality. The equipment is also a modular mobile system which includes a heat
exchanger and gas separator suitable for oil wells and gas deposits. The method reduces the prime cost
of the process.
The apparatus consists of 4 mobile gas separation units each of which consists of a heat exchange-
condenser; a separator and a fraction separating set. The initial gas is brought to the first heat
exchange-condenser via a pipeline. The gas flows through the heat exchange – condenser in the gas
separator. Here the newly formed liquefied gases flow to the bottom of the separator and into a secure
set while the remaining gases flow into the next gas separating units.
Here is a written explanation of the above diagram. The initial associated gas, which has been
separated from the oil production at 0.002-0.24 MPa pressure (0.02-2.4 kg/cm2), enters the heat
exchange-condenser (5-2) in module 2. The relevant gases are liquefied and separated from the
remaining residual gases in the following step (6-2) to obtain a wide spread of light liquefied
hydrocarbon fractions. The heat exchange-condenser (5-2) is connected to a gas separator (6-2) and
thus the speed of inflow gas does not change resulting in favourable conditions for saturated light
hydrocarbons and minimises liquid fraction waste.
The residual, uncondensed gas enters the next mobile unit (3) and into the heat-exchange-condenser
(5-3). This stage is concerned with the liquid separation of n-butane and iso-butane from the
remaining gas using gas separator (6-3). The time spent in contact with the coolant prevents the
possibility of propane condensing with iso-butane and butane liquid gas.
The remaining residual, uncondensed gas enters via pipeline (10) into the final heat-exchange
condenser (5-4) in module 4. This step separates the final propane liquid fraction in (6-4). The
apparatus uses well-established manufacturers of heat-exchangers and separators.
Invention formula
- This method in question is a stepped cooling method using outer heat transfer.
- The initial gas is put under pressure 0.002-0.24 MPa (0.02-2.4 kg/cm2).
- Each cooling step removes a different hydrocarbon compound.
- The modular equipment includes a heat exchange-condenser and separator.
- The stepped process removes the need for an expensive compressor
- The equipment contains no less than two consecutive modules
2009 103
Patent Description
Methanol Production
Patent holders: Lapkin Alexander Nikolaevich (RU), Lapkin Sergey Aleksandrovich (RU).
Authors: Lapkin Sergey Aleksandrovich (RU), Lapkin Alexander Nikolaevich (RU).
Request N.o. 2004104291
Invention priority: February, 4 2004
Registered in State Register of
Inventions in Russian Federation in August, 20 2005
Patent expired date is February 4, 2024
The Chief of the federal service on intellectual property, patents and trade marks is B.P. Simonov.
Russian Federation
Federal service on intellectual property,
patents and trade marks
(12) Invention formula to patent of Russian Federation
(21), (22) Request: 2004104291/04, 04.02.2004
(24) Commencement of patent: 04.02.2004.
(45) Published: 20.08.2005. Bul N.o. 23
(56) Documentations list cited in report on search: RU 2124387 C1, 10.01.199
RU 2117520 C1, 20.08.1998
WO 02096845 A2, 05.12.2002
US 5496859 A, 05.08.1996
Contact address: 445056, Tolyati, 40 Let Pobedy Street, 84 mailbox 1261, H.E. Romaneeva.
(54) Methanol Production
2009 104
At present methanol production takes place at processing facilities far from gas and oil fields. The natural
gas is often pumped via pipeline at extreme pressure (7.0 -10.0 MPA) or transported via road networks using
tankers. Gas pipelines are extremely expensive and often make gas utilization unprofitable in the process.
This results in either gas flaring or closure of the plant.
2009 105
One method of producing methanol from natural gas involves two stages at high pressure and
temperature. In the first stage the synthesis is made in flowing reactor and in the second stage in reactor with
recycle. Additional gas stream is added to the gas at the second stage which has excess hydrocarbons or
carbon monoxides for volume correlation regulation of CO/ (H2+CO2). At this stage preliminary reduction
of the carbon monoxide from dioxide takes place in additional reactors (Patent of RF N.o. 2052444, C 07 C
31/04, 1996). This method requires considerable power inputs to maintain desired pressure and temperature
especially for the oxide reduction process.
Another method to produce methanol uses oxygenated-steam conversion of natural gas into syn- gas
under heat and pressure 8.5-9.0 MPa (Patent of RF 2135454, MPK 6 C 07 C 31/04, 1999). However
oxygenated-steam is an expensive product, carbon dioxide must be removed and high quality equipment
such as compressors is required. Equally it is possible to produce methanol again using the oxygenated
steam conversion of natural gas, but it is possible to separate carbon dioxide from the converted gas with the
following dry and compression up to 8.5-9.5 MPA (Patent of RF 2099320, MPK 6 C 07 C 29/15, 1997).
Again the disadvantage of the method is expense of protecting the oxygenated-steam process and removing
carbon dioxide which requires large energy resources.
One method that produces methanol from natural gas requires natural gas to be extracted under pressure
and extreme heating. This leads to gas desulphurization. The resulting syn-gas is converted into methanol
using catalytic steam. The technique utilizes residual heat and unreacted gas is recirculated. Finally methanol
is separated from the other products. (Patent of RF 2124387, MPK 6 C 07 C 27/26, 1999). This method
suffers from considerable power inputs and the necessity for a compressor.
The aim of the invention was to obtain methanol from new gas deposits with unstable gas composition at
low pressure without the use of expensive compressors which would allow for mobility of the equipment.
The present task was accomplished by being able to select gas of unstable composition and undergo
desulphurization and steam-gas mixture generation under the pressure not less than 0.001 Mpa at the same
time. Methanol synthesis is carried out using a minimum of two consequent flowing stages depending on the
quality of the methanol required by the costumer. The process uses two catalyst systems for which reduces
the pressure required to below 1.5 Mpa. The gas pressure stepped stabilization is carried out with the help of
gas-jet equipment.
- The apparatus solves both ecological and economical problems by being able to process unstable gas
compositions and being able to utilize APG production from old and new deposits where otherwise it
would be flared.
- Expensive compressors are not required with this method and allow the equipment to be mobile
- Low pressure apparatus also enables gas desulphurization to be combined with the pressure stepped
stabilization stage using the gas jet apparatus.
- Methanol synthesis takes place in no fewer than two consecutive flowing steps which removes the
necessity for synthesis gas circulation necessity and allows isothermal and adiabatic type reactors to
remain at low pressures.
Method according to diagram (below)–
- Hydrocarbon gases of unstable composition and pressure (0.001-20 MPa) enter the pressure stabilization
bloc.
- The first step removes both inert gases and sulfur derivatives.
- Syn gas products, CO, H2 and CO2 are produced in line 2 after natural gas is exposed to previously
heated steam (650-750 C°) and to the appropriate catalyst in a pipe furnace.
- Combustion of residual gases heats the pipe furnace. (heat utilization)
2009 106
- The syn gas flows through the system into a recuperator (4), which heats up and cools down the syn gas
very quickly. This allows for quick collection fo steam condensate in the boiler-utilizer (5).
- This process is repeated using both a heater (6) and condenser (7) to utilize all the syngas.
- Methanol synthesis takes place in line 9 under catalyst reform in isometric reactor blocs at the 180 – 280
C° and 2-5 MPa.
- The resulting dry gas passes through the recuperator (10) and condenser (11) and leads to the separation
of newly formed methanol and residual gases.
- The synthesis steps can be 2 up to 8 depending on initial gas pressure and composition.
- The residual gas is flared as fuel in the pipe furnace.
Methanol schematic 1 -
2009 107
Methanol schematic 2 -
Refer to schematic 2 -
For methanol production APG passes through separator E-1and into the compressor setting KY-1, where the
gas mixture pressure increases up to 20 kgs/cm2. The APG then enters the reforming furnace heater ПР-1
and goes to the flow mixer where formation of steam gas mixture in proportions is: steam/gas + 2.5/1. The
steam gas mixture moves to the reforming pipe. The synthesis gas formed in the reaction goes to consecutive
heater furnaces, T-1, T-2 and separator E-3, where it is cooled and separated from the condensate (water).
Dry synthesis gas moves to the compressor setting KY-2, where gas mixture pressure increases up to 55
gks/cm2. Then the synthesis gas again enters consecutive heat exchangers T-3, T-4, where the temperature
increases up to 220-240 C°. And then it‘s given to the pipe reactor P-1. Reacted methanol mixture passes
through recuperater T-6 and is cooled in the heat exchanger T-8 and is separated in E-5. Discharge synthesis
gas with the high methanol and metric slug content goes to gas mixture bloc separation БРГ-1. Methanol
mixture goes to be flared in furnace ПР-1 and synthesis gas goes to the compressor setting KY-2. Methanol
raw goes to the column K-1 from separators E-4, E-5 where water and methanol separation is. Purified
methanol is sent to the storage from the separator E-6.
For methane After the preliminary separation from water and sulfur compounds in the equipment E-1, APG
is compressed in the setting KY-1 up to 50 at and is cooled in the air refrigerant T-1 and goes to the dry
apparatus E-2 (T-3) where purification from water and sulfur compounds is. Then the gas mixture goes to
the heat exchanger T-3 where is condensation of the main hydrocarbon mass C3+. Gas liquid fraction goes
to the separator E-5. Liquid fraction goes to the column K-1. And then gas goes to the KY-1 and condensate
to the storage from the cube part of column K-1.Gas fraction enters the recuperator T-9 and then to the
column K-2 where it is purified from the CO2 and additional water. The Purified gas goes to the compressor
setting KY-4 where is compressed up to 250 at. Then gas mixture passes through the refrigerant T-8,
recuperator T-9, T-10 and into the throttle valve and then to the separator E-8. The liquid methane fraction
goes to the storage and gas fraction via recuperator T-10 to the KY-4.
2009 108
Closed joint-stock company
―GLOBOTEK‖
Technological process of methanol-rectifier from APG of oil and gas production workshop ―Smorodinka‖
(OAO ―Saratovneftegaz‖) with capacity 50 000 000 nm3/year on initial raw.
During the methanol production from APG it is necessary to realize the following technological processes.
- Purification (preparation) of water
- APG purification from sulfur compounds
- Technical nitrogen production
- Methanol synthesis
- Methanol mixture purification from the dissolved gas and water.
In the methanol production technological scheme were the following methods realized:
- Adsorption purification (by molecular sieves)
- Water and gas mixture separation in the membrane settings
- Steam reforming
- Methanol synthesis at the average pressure
- Methanol raw rectification
Preliminary technical indices
N.o Index name Unit Indices
1. Initial gas mixture discharge (Supplement 1) Nm/year 50 000 000
2. Electric power consumption Megawatt/y
ear
21 600
3. Prepared gas mixture consumption in gas-turbine power plant Nm/year 6 480 000
4. Gas mixture consumption as raw Nm/year 24 000 000
5. Prepared water consumption Ton/year 35 890
6. Methanol raw yield (water content up to 15 %) Ton/year 55 300
7. Methanol-certificate yield Ton/year 50 000
Electric power and gas mixture consumption is expected at the reciprocating compressor setting work,
without taking water into account. Methanol yield is expected without taking catalyst activity rating into
account and membrane bloc fading.
Closed joint-stock company
―GLOBOTEK‖
Technological process of methane fraction liquation of APG of oil and gas production workshop
―Smorodinka‖ with capacity 50 000 000 nm3/year
During the liquation of methane fraction of APG it is necessary to prepare initial gas mixture.
- Purification from the water
- Purification from sulfur contained mixtures
- Purification from hydrocarbon dioxide
- Purification from methane‘s homologies
Physicochemical description of APG is presented in the Supplement N.o.1
Concise description of technological scheme is presented in the Supplement N.o2.
In technological process of preparation and liquation of methane fraction are the following methods realized:
- Adsorption purification (by molecular sieves)
2009 109
- Absorption purification (by methanol)
- Simple regenerating cycle with gas expansion
Preliminary technical indices
N.o Index name Unit Indices
1. Initial gas mixture consumption (Supplement 1) Nm/year 50 000 000
2. Electric power consumption Megawatt/y
ear
30 240
3. Prepared gas mixture consumption in gas-turbine power plant Nm/year 9 072 000
4. Prepared gas mixture consumption Nm/year 1 296 000
5. Gas condensate yield from the К-1 Ton/year 11 232
6. Liquid methane fraction yield from the separator Е-8 Ton/year 21600
Closed joint-stock company
―GLOBOTEK‖
Supplement N.o.1
APG physicochemical composition under different conditions -
Pressure: 3 kgs/cm3
Temperature: 20 C°
Discharge: 50 000 000 nm3/year (5787 nm3/hour) at the 8640 hour/year
APG component composition:
Condensate physicochemical quality
Saturated steam pressure at the 40 C° is 6.27 kgs/cm2
Capacity at the 40 C° and 6.3 kgs/cm2 is 526.2 kg/m3
Discharge is 1330 kg/hour (11 491 200 kg/year) at the 8640 hour/year
2009 110
2009 111
Gas Flaring Articles
Russia top offender in gas-flare emissions
US study uses satellite images for findings
Many oil wells, such as this one off the coast of Mexico, burn off natural gas that is a byproduct of drilling.
A study said such practices produce 400 million tons of carbon dioxide each year. By John Donnelly, Globe
Staff | June 21, 2007
WASHINGTON -- A little-known but major contributor to global warming -- gas flaring at oil wells -- has
been measured for the first time using satellite imagery and shows that Russia is burning three times more
gas than previous estimates, making it the world's worst offender, according to a new US study.
At many oil drilling sites around the world, producers ignite excess gas, sending huge balls of fire into the
sky. Environmentalists and World Bank analysts say the practice -- called gas flaring -- needlessly harms the
environment and wastes a lucrative energy source.
When companies drill for oil in underground caverns, their equipment brings to the surface both petroleum
and natural gas. Producers burn the gas because they have no infrastructure to use it, or no immediate
consumer. In some cases, such as at some of Russia's isolated oil wells, the nearest possible user of natural
gas could be more than 1,000 miles away.
The report was completed by scientists at the US National Oceanic & Atmospheric Administration in
Colorado using Air Force meteorological satellite images dating to 1995. It reveals that the amount of
carbon dioxide emitted from Russia's gas flaring alone equals the combined emissions from all cars and
trucks in New York state and New England.
In all, the emissions from global gas flaring send 400 million tons of carbon dioxide into the atmosphere
every year -- equivalent to the emissions from all the vehicles in Great Britain, France, and Germany.
The World Bank is convening a meeting today in Rome to discuss the 108-page report's findings. Experts
estimate that the amount of gas released and burned at oil installations is equivalent to a quarter of the US
natural gas market, potentially worth $69 billion annually at current prices.
The study's main author said he hoped the report would begin to curtail the practice.
"It's possible this will provide some impetus toward reducing the flaring," said Chris Elvidge , a physical
scientist at NOAA's National Geophysical Data Center . "Countries know they no longer will be able to flare
and have no one know about it. Now there is a technology that allows gas flares to be identified and tracked
over time."
Despite the logistical difficulties and costs in channeling the excess gas to users, officials say it could be
done. The gas could be funneled into pipelines and delivered to cities or industries. It could be turned into a
liquid diesel, or it could be reinjected into oil wells to help the process of excavating more oil.
2009 112
Peter J. Robertson, Chevron's vice chairman of the board, said in an interview yesterday in Washington that
his oil company has plans to use all three approaches in Nigeria and Angola, including a project that pipes
gas from Nigeria to Togo, Benin, and Ghana in West Africa. In Nigeria, he said, the company "will put out
all our flares" within the next few years.
"I think we will see major reductions" globally in the next two to three years in gas flaring, said Bent
Svensson , program manager for the World Bank's Global Gas Flaring Reduction program, which started
five years ago. He cited commitments from Nigeria, Equatorial Guinea, and Kazakhstan to phase out flaring
entirely within the next several years.
David Hawkins, director of the Natural Resources Defense Council's climate center in Washington, said gas
flaring "is very important to address. Global warming is a problem that requires addressing a fairly long list
of activities, and this is one of them."
The US report focuses just on gas burned at sites, not gas that is released, or vented, into the atmosphere.
Some of the natural gases are methane, which traps 23 times more heat in the atmosphere than carbon
dioxide. Experts do not know the severity of the problem since venting is so difficult to measure.
The report found that global gas flaring worldwide has remained "largely stable" during the past 12 years,
emitting roughly 150 to 170 billion cubic meters of gas. But during that time, individual countries fluctuated
greatly in the amount of gas flared.
Countries that decreased flaring included Nigeria, Angola, and Cameroon, according to the report. Russia
had the largest increase, followed by Kazakhstan and Iraq, the report said.
In Iraq, experts say, the amount of gas flaring appeared to be related to the US invasion in 2003, citing an
increase in 2004 to 8.3 billion cubic meters, up from 6.7 billion the year before. Since 2004, the amount of
flaring has decreased slightly, but still remains roughly double the amount from 1995, during the early years
of sanctions against Saddam Hussein's government.
World Bank officials said they were hopeful that Russia would reduce gas flaring, which the report
estimated at 50 billion cubic meters, or roughly one-third the world's output; Nigeria is second, at 23 billion,
following by Iran, Iraq, and Kazakhstan.
In 2004, Russia reported flaring just 15 billion cubic meters. President Vladimir Putin, in his address to the
Duma two months ago , increased that estimate to more than 20 billion cubic meters.
Putin told the Russian federal assembly, "Such wastefulness is unacceptable. It is necessary without further
delay to create an accounting system for associated gas (burned during excavation), increase environmental
penalties, and introduce stricter requirements" to capture the gas.
François-Régis Mouton, an adviser on gas flaring at the World Bank, said that "as soon as Putin decided to
put it at the top of the agenda," federal Russian officials showed more interest in tackling the problem.
A Duma committee on energy recently decided to host a meeting in Moscow in October on ways of
reducing flaring.
2009 113
The United States has several oil production sites that flare gas, but they use 99.5 percent of gas from oil
installations, said James Slutz, deputy assistant secretary for oil and natural gas at the US Department of
Energy.
Slutz said the US report should help reduce gas flaring globally because satellite imagery would keep
countries honest. "As reporting gets better," he said, "we should see more action."
By John Donnelly, Globe Staff | June 21, 2007, [email protected]
© Copyright 2007 Globe Newspaper Company.
Fines for Burning Associated Gas Soar
Russia -
Nov. 13, 2007 – The fine for burning associated petroleum gas may be raised substantially. The Federal
Service for Ecological, Technological and Atomic Supervision (Rostekhnadzor) will introduce a draft
resolution to the government next week to raise the fine by 163.48 times on January 1 of next year. Under
the resolution, at that time, the payment for releasing byproducts of the burning of associated gas within the
limits set will be 3,495 rubles ($145) per ton. Above the limit, it will cost 17,475 rubles ($730) per ton.
Those rates will be approximately doubled in 2010, increased by 2.5 times in 2011, and tripled in 2012.
Today, the fines for releasing associated gas without burning it is 163 times higher than for burning the same
amount of gas. Rostekhnadzor wants equalize the fines. Companies paid 64.2 million rubles for burning
associated gas in 2006. Under the new rates, they would pay 10.5 billion rubles to burn the same amount.
The resolution has already been conciliated with the Finance Ministry, Ministry of Health and Social
Development, Ministry of Natural Resources and Ministry of Industry and Energy. The Ministry of
Economic Development and Trade has yet to approve the document. Analysts note that the new fines may
hinder oil production in Eastern Siberia, where there is no infrastructure for collecting associated gas. That
may pose a threat to the Eastern Siberia-Pacific Ocean pipeline. The fines are also likely to discourage small
oil companies from developing difficult to access deposits.
Rostekhnadzor press secretary Evgeny Anoshin commented that the goal of the resolution is to minimize the
damage caused by the burning of associated gas and that the agency is ready to listen to suggestions for the
proposal.
www.kommersant.com
Nigeria -
The Nigerian Department of Petroleum Resources, DPR, has said that a decision on when to start enforcing
fines on companies that continue to flare natural gas after the targeted deadline has been set. According to
the government, any company flaring after January 1, 2008 will be responsible for fines of $3.50 for every
1,000 standard cubic feet of gas flared. The DPR also said that oilfields still flaring gas would be closed
down after December 31, 2008.
The DPR says it wants to enforce the drastic measures and bring an end to back-and-forth dialogue between
the government and foreign operators. From January 1, government will impose fines on operators that still
2009 114
flare gas and from December 31, 2008, the oilfields of defaulting operators will be shut, Oliver
Okparaojiako, a senior DPR official, told a public hearing about flaring at the National Assembly.
The fines for flaring should bring a tidy sum to the government, as most companies say that they will not be
able to meet the deadline but the honeymoon from fine revenue could be short-lived as shutting down oil
fields at the end of next year could cost the government even more revenue.
Oil industry executives present at the public hearing said they doubted whether the DPR would be able to
enforce the measures, especially as shutting down over 100 oilfields would be a disaster for Nigeria‘s public
finances.
Source: Petroleum Africa
Nigeria: Norway to help cut down on gas flaring and oil spill
07/01/2008
Determined to achieve zero gas flare-out by December 31, 2008, the Federal Government of Nigeria in
conjunction with oil companies operating in the country has set up an ad hoc Flare Reduction Committee
with a mandate to come up with a road map for elimination of routine gas flaring within a realistic time
frame.
This is coming on the heels of an agreement signed by the Federal Government and the Kingdom of Norway
on how the latter could assist the country to check oil spills and reduce gas flaring.
President Umaru Musa Yar'Adua had late last year announced the new Gas Flare-out date following the
inability of oil companies to meet the January 1, 2008 deadline earlier agreed. The two countries met in
Abuja last October 29 to discuss issues affecting their petroleum sectors under the Memorandum of
Understanding (MoU) on Development and Co-operation in Oil and Gas Related Industries signed by both
countries in 2000.
The Minister of State for Petroleum, Mr. Odein Ajumogobia, SAN, who led other top government officials
to the meeting, had solicited the support of Norway on the possibility of trapping and storing carbon dioxide
from oil production, power plants and industrial operations as part of measures to protect Nigerian
environment.
The minister had also canvassed more information on trapping and storing of the greenhouse gas, based on
Norway s experience.
In a communiqué issued at the end of the meeting obtained, it was agreed that Norway would assist Nigeria
in its aspiration to reduce gas flaring. It was further agreed that the Norwegian Government would assist
Nigeria in developing oil spill monitoring and environmental regulations as well as to develop competencies
and capacities in environmental impact assessment analysis.
2009 115
Based on its experience, Norway, the parties agreed, would provide the requisite training and transfer of
knowledge, while the Nigerian government would provide counterpart funding as may be required under the
partnership.
Confirming the setting up of the committee at the weekend, Group General Manager (GGM), Public Affairs
of the Nigerian National Petroleum Corporation (NNPC), Dr. Levi Ajuonuma, stated that the committee was
currently working with experts in the preparation of assessments on the environmental, health and financial
impacts of ending or continued routine gas flaring in the country after December 2008.
He explained that the Flare Reduction Committee would limit its mandate to gas flare reduction adding that
its terms of reference include the review of each company s flare reduction programme to ascertain whether
any acceleration is realistic and, where possible, to a decision on how this can be achieved.
The committee, he noted, was directed to conduct an assessment of health and environmental consequences
of continuation of routine flaring and to integrate individual company plans into a Nigeria Flare Reduction
Plan and Nigeria s Gas Master Plan.
The GGM added that the gas committee would look for opportunities for co-operation between operators
and for demand clusters and amend the Flare Reduction Plan as required following agreement with all
stakeholders.
Other tasks before the committee include developing and implementing of a communication strategy that
clearly lays out how and when flare reduction will take place; agree on clear milestones and action plan with
the assistance of the Department of Petroleum Resources (DPR) and monitoring the implementation of the
integrated Nigeria Flare Reduction Plan.
In an effort to achieve the gas flare-out target set for 2008, major stakeholders recently came together in a
newly created forum for cooperation that will develop a road map for the elimination of flaring within a
realistic time frame, taking into account the complex challenges that inhibit a faster reduction of gas flaring
in Nigeria.
High-level representatives from several ministries and sector companies agreed at the meeting to establish
an ad hoc Flare Reduction Committee to reduce routine flaring to a minimum within the shortest possible
time frame. The work of the Committee, which is being facilitated by the World Bank Global Gas Flaring
Reduction Partnership (GGFR), aims to be forward looking, act quickly, with a clear deadline and mandate
to manage flare reduction in Nigeria," Ajuonuma said.
In the process of oil production, Nigeria flares or burns about 24 billion cubit meters (or 0.84 trillion cubic
feet) of associated natural gas every year. The World Bank GGFR estimates that globally, 150 billion cubic
meters (or 5.3 trillion cubic feet) of associated natural gas are being flared and vented annually. That is
equivalent of 25 per cent of the United States gas consumption or 30 per cent of the European Union gas
consumption per year. It is also estimated that global gas flaring releases about 400 million tons of CO2 per
year into the atmosphere," he said.
Some of the major inhibitors to a faster gas flaring reduction in Nigeria include: lack of adequate
infrastructure to transport the gas, inequitable gas pricing, lack of capital for gas utilisation projects, security
issues in the Niger Delta.
Speaking on the issue, Minister of State for Gas, Mr. Emmanuel Odusina, who is also the chairman of the
committee, assured Nigerians that government and the industry remained fully committed to the elimination
of routine flaring.
2009 116
"We share responsibility for not achieving bigger results, some progress in flaring reduction has been
achieved but it is clearly not enough. That is why we have created this Flare Reduction Committee to come
up with a road map for elimination of routine flaring within a realistic time frame, in a joint effort by
government, industry and other stakeholders so we can attain bigger gas flaring reduction," Odusina said.
The World Bank had at the last December Global Forum on Flaring Reduction and Gas Utilisation in Paris,
called on oil producing countries and companies to step up efforts in reducing the flaring of natural gas as a
way of mitigating the impact of climate change and lowering greenhouse gas emissions.
The Gas Flaring Committee is made up of heads of Ministry of Energy (Gas), Ministry of Energy
(Petroleum), Ministry of Finance, Department of Petroleum Resources, National Planning Commission,
Special Advisors to the President on Petroleum, Revenue Mobilisation Allocation and Fiscal Commission,
NNPC, World Bank GGFR and all the multi-national oil companies.
Source: This Day
Nigeria's Senate to Probe Extension Of Gas Flaring Deadline
IBADAN, Nigeria -(Dow Jones)- The Nigerian Senate has set up an ad-hoc committee to investigate the
government's extension of a deadline to end gas flaring.
The deadline was originally fixed for Jan. 1, 2008 but Nigerian President Umaru Yar'Adua announced late
last year a shift to Dec. 31, 2008.
The ad-hoc committee set up Thursday comprises members of the Senate committees on gas, environment
and petroleum (upstream). It was set up following the adoption of a motion sponsored Thursday by Grace
Bent, chairman of the Senate Committee on Environment.
Bent said "broken promises, lack of commitment, shady deals and ignored legislation have marred the
history of flare-out target in Nigeria."
She said that from available statistics, Nigeria contributes more to global warming and greenhouse emissions
than any other country in Sub-Saharan Africa to the extent that "the opening that has been created in the
ozone layer by these emissions is larger than the size of West Africa."
Bent stated Nigeria flares more gas than any other country in the world, with 2.5 billion cubic feet of gas a
day, the equivalent of 40% of all natural gas used on the continent of Africa.
Oil companies in Nigeria have said a lack of funding by the government, with which they have joint venture
agreements, has made it impossible to end gas flaring.
The Senate called on the Nigerian government "to meet up with its agreement towards contributing to
counterpart funding that will be used in developing the gas sector."
2009 117
Civil society groups and community leaders in the Niger Delta last week petitioned the Senate and the
House of Representatives, seeking legislation to compel oil companies and the government to end gas
flaring in the region by 2008.
Anne Pickard, regional vice president of Shell's exploration and production unit in Africa, said ending
flaring at some 1,000 wells across Nigeria could cost up to $6 billion.
Nigeria's natural gas reserves, estimated at some 184 trillion cubic feet, are ranked eighth in the world.
Gas flaring has in practice been outlawed in Nigeria since the Associated Gas Re-Injection Act was
introduced in 1979. The act, which was amended in 1985, compels multinational oil and gas producers to
submit gas utilization programs.
The initial intent of the act was to stop gas flaring by January 1984. The 1985 amendment allowed the
imposition of a penalty for gas flaring. The date to end gas flaring was later shifted to 2008.
An oil and gas industry source in Lagos said the Senate may be working towards putting a legislative
instrument in place to stop gas flaring by the end of 2008.
Source - Obafemi Oredein, contributing to Dow Jones Newswires; 234 2 751 0489
Oil industry Jargon de-coded
What comes out of an oil field?62
Major: Crude oil. (Texas tea, Black gold)
Minor: Gas (Natural gas, Methane).
Condensate and natural gas liquids (only sometimes found in an oil field)
Crude Oil
Crude oil comes in a variety of colours and thicknesses. It may be black, it may be brown, and it may be
even be greenish. It may be relatively thin or relatively thick.
The 'thickness', or density, of crude is measured against a scale developed by the American Petroleum
Institute. The denser and heavier the oil, the lower on the 'API' scale it is.
Regardless of what it looks like, the raw crude oil as it is pumped out of the ground is not much use. To be
able to use crude oil, the different components that make it up need to be separated out. Crude oil runs
through various processes in oil refineries which separate out various proportions of the constituents of that
particular crude. Depending on how the crude was formed, varying combinations of component parts
('fractions') are yielded. Crude from one field may have a different 'yield profile' to crude from a field
elsewhere.
Several thousand different chemicals can be identified in the various crude oils.
The huge pressure and high temperature in the deep underground oil reservoir means that some chemical
62
Sustainable Living Organisation, 2006, http://www.naturalhub.com/slweb/defin_oil_and_Natural_Gas.html
2009 118
compounds which would be gases at normal temperatures and pressures above the ground remain liquid
under the ground, and form a part of the liquid crude. When the crude is pumped up from the depths, the
pressure is released and temperature drops. The liquified gases in the crude are then released.
This is normally methane, and is not usually associated with any other volatile compounds which liquify at
normal above-ground temperature and pressure. The gas usually associated with oil wells is therefore called
'dry gas'. Historically, the gas that bubbles out as the crude comes to the surface has simply been diverted
and burnt ('flared off') from the top of a tall pipe at the well head.
Light crude
Depending on the field, some crude oils are naturally 'runny' and light. They are easy to refine, and are
highly sought after. These are lower density oils.
Sweet crude
Sweet crude oil containscontains very little sulfur in it. Excess sulfur has to be removed from crude at the
refinery. This is an expensive process.
Heavy crude
This refers to very thick, viscous, and heavy crudes. Heavier oils are often found relatively close to the
surface. Any lighter and more volatile components would have been vapourised over time. They comprise of
large molecules such as hexadecane (16 carbon & 34 hydrogen atoms, or C16H34) and octadecane (18 carbon
& 38 hydrogen atoms or C18H38). These large molecules are split or 'cracked' into smaller molecules such as
Hexadecane - in effect fuel oil – and later cracked into a mix of octane, hexane, and a little ethylene. Octane
and hexane are components of gasoline.
Sour crude
Some crudes are naturally high in sulphur. If there is more than 2.5% sulfur present, they are called 'sour'
crudes.
Petroleum Gases
The pressure and high temperatures in the deep underground gas reservoir means that some low boiling
point hydrocarbon compounds (which would be liquids at normal temperatures and pressures above the
ground) become gases under the ground.
These 'gasified liquids' form a part of the flow of gas when it is piped up from the reservoir. When the gas is
flows up from the depths, the pressure is released and temperature drops. The 'gasified liquids' in the cooling
gas stream then condense (just as steam condenses back to water as it cools). These liquid condensates and
natural gas liquids are quite usual in gas fields. The gas from gas fields is therefore usually 'wet gas'.
Gas
A percentage of crude oil fractions will be gaseous at room temperature and pressure. This is normally
methane and is historically called ―dry gas.‖ ―Wet gas‖ refers to other gaseous crude fractions with a higher
molecular weight (C2 – C5). These gases have for many years been flared/vented at the well head.
Natural Gas
This is almost pure methane (CH4), which remains a gas at room temperature and pressure. Natural gas is in
Liquid state when cooled to below -161.5 oC, or subjected to very high pressures (or a bit of both). Thick
walled cylinders must be used to hold compressed natural gas in CNG powered vehicles to withstand the
high pressures needed to put useful amounts of natural gas into the tank. On ships natural gas is often
refrigerated to reduce the pressure needed is reduced.
Condensate
2009 119
Condensate is made up of three hydrocarbon molecules containing from 8 to 12 hydrogen atoms that are
required to form liquefied natural gas, namely propane, butane, and pentane. The smallest of these 3,
propane, liquifies at -42oC. The largest molecule, pentane, liquifies just below 36
oC. When mixed together,
they are sold as 'liquefied petroleum gas', or LPG. This gas can be held in relatively thin walled bottles and
is sold worldwide for both domestic cooking as 'bottled gas' and as a transport fuel.
Natural Gas Liquids
Liquid hydrocarbons such as hexane and heptane, can be recovered from the gas stream. They can be used
as a component of gasoline, but have to be blended with other liquid hydrocarbons from distillation of crude
oil in order to be useful as gasoline. Natural gas liquids cannot be counted as 'oil equivalent' by themselves,
as they depend on crude oil to become useful.
What happens at a refinery?
Crude is heated through a defined temperature range which causes the separation of different crude
fractions. The light fractions condense at the top of the fractionating towers where temperatures are not more
than 200oC, and the vapors of the low boiling point fraction of the crude are drawn off and condensed. It is
hotter lower down the column, and higher boiling point liquids are first vaporised, then drawn off and
condensed at this lower point.
These tall column stills are known as 'fractionating towers'. The the temperature is considerably less and
vice versa. The distilled liquid fractions may then be further refined by removing impurities.
The less desirable higher boiling point liquids that make up 'kerosene' are usually further broken down using
catalysts to form more desirable liquids suitable for gasoline or for making aviation gas. The gasoline liquids
from this process are blended with 'straight run' gasoline. A variety of other chemical techniques, such as
isomerisation and dehydrogenation, are used to improve some refinery liquids for use in gasoline.
The light gas oils, or fuel oils, can either be further split for manufacture of more gasoline, or retained and
refined for when demand for furnace oil is high (winter), or when extra quantities of diesel fuel are needed.
The type of irreducible residues that remain from distillation depends on the makeup of the crude. It may be
tars, or 'asphalt'
Heavy crudes contain fewer valuable crude fractions such as gasoline and therefore require greater
processing to achieve the desire components. This is expensive to buy as the cost of dealing with them is
significantly higher and there is less profit in them. In addition, they require specially configured refinery
processes requiring more capital to build. Once built, refineries handling heavy crudes make more gross
profit (at least) than refineries handling light crude - but only so long as heavu crudes sell cheaper. As more
refineries are converted to handle heavy crudes, demand will go up, and the price advatage reduce.
Heavy crude takes more energy to process than light crude. Overall, there is and requires roughly 14%-18%
more energy therefore heavy crudes are cheaper to purchase.
The gasoline-burning national car fleet of the USA means that USA refineries try to maximise gasoline
production, whereas the increasingly diesel-powered European car fleet means European refineries try to
maximise light gas oil and diesel. European refineries typically break a barrel of crude oil down into about
25% gasoline, 50% light gas oil/diesel where USA refineries typically break a barrel of crude down into
around 50% gasoline and 25% diesel/heating oil.
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Gasoline
Crude oil (UK) or Petroleum (USA) is heated to extract the crude fractions with some of the lowest boiling
point. These fractions include pentane, hexane, heptane, octane, decane, and dodecane which are all liquid at
room temperature. Pentane is the lightest liquid with a boiling point of 36oC while Dodecane is a liquid until
215oC. When these six liquid hydrocarbons are put into a mixture together, the mixture is called 'gasoline'.
Some of the lighter liquids are chemically 'reformed' to make them more suitable as a car fuel.
The heptane is a straight chained hydrocarbon molecule which tends to combust very quickly in high
compression engines, causing pre-ignition or 'knocking'. A chemically 'reformed' branch-chained form of
octane (C8H18), 'iso octane', is considered the ideal fuel, as it combusts at a slower pace, giving better
compression. Iso-octane is given a nominal rating of 100, as the perfectly combusting fuel for modern high
compression car engines. Heptane, on the other hand, is given an 'octane rating' of zero.
Blends of gasoline are measured against a standard ‗octane rating‘ (the 'Research Octane'). The closer to 100
the 'octane rating'* of the gasoline blend is, the better the explosion profile in the engine and the less
tendency of knocking.
Nowadays modern engines use electronics to automatically adjust the fuel:air ratio for an optimal
combustion pattern regardless of the octane rating (to a point). A barrel of crude ultimately yields about
45% in gasoline products.
* Most of the world uses the 'Research Octane Number' (RON) to measure octane. The USA uses an average
of RON plus the 'Motor Octane Number'. Thus a 91octane fuel is the equivalent of 87 in USA.
Kerosene
This is combination of the two heaviest and least volatile components of gasoline, decane and dodecane. A
specially modified blend of kerosene (avgas) is used in jet engines. A barrel of crude ultimately yields about
4.5% kerosene.
Fuel oils or light gas oil
The heavier crude fractions are hexadecane and octadecane. These molecules are often heated up and further
split (with the aid of a catalyst) into more useful products. Hexadecane (C16H34), for example, can be split
into various proportions of octane (C8H18), hexane (C6H12) and a small amount of ethylene (C2H4). The
octane and hexane liquids are used as components of gasoline.
Light gas oil is also further refined into grades for home heating fuel oil, and highly refined grades for
diesel. A barrel of crude ultimately yields about 36.5% fuel oil.
Lubricating oils
The fraction of the crude that has very many carbon atoms is used as liquid lubricant.
A barrel of crude ultimately yields about 2% lubricating oils.
Grease
These are even larger crude fractions and account for roughly 2% of a barrel of crude.
Paraffin wax
The heaviest molecules in the crude are solids at normal temperatures. Paraffin wax is used for candles.
Averaged, a A barrel of crude ultimately yields about 11.5% grease, paraffin wax, tars, ethylene and other
miscellaneous products.
The cultural divide
In America, the fuel we put in our cars tank is 'gasoline', always shortened to 'gas'. The tank is called a 'gas
tank'. In the UK and former colonies, the fuel we put in our cars tank is 'petroleum', always shortened to
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'petrol'. The tank is called a 'petrol tank'. (But the American term 'gas; has infiltrated the language and is
now used interchangably for 'petrol', and almost as frequently).
In USA, the oil that comes out of the ground is called 'crude', or it might be called 'petroleum'. (Petroleum is
literally correct, as it comes from the latin 'petra', stone, and 'oleum', oil). No-one in USA would think of
putting 'petroleum' in their car, because it would be tantamount to filling up with crude oil!
In the UK, many cars have been converted to dual fuel - they can run on gasoline or on compressed natural
gas. If a driver needs 'gas', they may need gasoline ('petrol') or they may need more natural gas..... In the
UK, the black liquid that comes out of the ground is either called 'crude', or simply 'oil'. Outside the oil
industry, crude is never called petroleum in the UK. The idea that you could get petroleum - the stuff you
run your car on - straight out of the ground would seem like a bizarre joke.
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Table 12- List of independent oil companies in Russia
As of 30-Sep-2004, 000 b/day Source: Nefte Compass, Vol XIII, No. 40
Aganneftegasgeologia 20.1 Michayuneft 0.05 Sheshmaoil 5.1
Aki-Otyr 0.1 Mellyaneft 2.1 SibinvestNaphtha 0.01
Akmai 0.1 Meretoyakhaneftegas 0.9 Sinko NNP 1.6
Abdulinskneftegas 0.05 MNKT 0.4 SMP-Neftegas 7.1
Aloil 2.9 MNTK Nefteotdacha 0.3 Sobolinoye 3.3
Archinskoye 0.4 Mokhtikneft 4.2 Stimul 6.4
Archneftegeologia 5.5 Nazymgeodobycha 0.3 Tarkosaleneftegas 13.6
Arcticmorneftegasrazvedka 0.7 Nazymskaya NGRE 0.8 Tatex 9.9
Bashmineral 1.3 Nedra-K 0.4 Tatnefteotdacha 4.8
Benodet Investments 15.6 Neft (Kirov) 0.1 Tatnefteprom 5.3
Bulgarneft 3.3 Neft (Saratov) 0.4 Tatnefteprom-Zyuzyeyevneft 6.9
CanBaikal Resources 1.5 Neftebitum (Krasnodar) 0.5 Taimyrgas 0.4
Chedty Neft 0.1 Nefteburservice 0.3 Tatoilgas 5.1
Chepetskoye NGDU 0.8 Neftinvest 1.3 Tebuk 0.03
Chernogorskoye 6.9 Neftus 2.3 TNGK-Razvitiye (Developmt) 4.4
VUMN (Chishmaneft) 4 Negusneft 20 Tomskaya Neft 2.3
DDM 0.04 Nizhnevolzhskgeologia 1.2 Tomsk Oil and Gas Co. 0.1
Derii 0.01 Nokratoil 0.2 Tomskneftegasgeologia 1.4
Dinyelneft 0.6 Norilskgazprom 0.1 Topneft 0.2
Dinyu 1.9 Northern Lights 2.9 Transoil 0.6
Druzhbaneft 0.3 Northgas 15.8 Trans-oil 0.4
East Transnational Co. 1.9 Novatek (Novafininvest) 0.3 Troitskneft 3.2
East-Ural-Neft 0.2 Oil Co. Kalmpetrol 0.9 Tsetan-Geo 0.5
Eko-Neft 0.2 Oil Co. Recher-Komi 0.5 TsNPSEI 1
Frolovskoye NGDU 0.6 Orenburggeoneft 1.4 Udmurt National Oil Co. 2.3
Futek 0.1 Orenburgnefteotdacha 0.5 Udmurtgeologia 3.3
Geoilbent 17.2 Orenburgtopneft 0.2 Udmurttorf 3.7
Geologia 3.3 Pechoraneft 5.9 Ural-Naphtha 0.1
Geological Exploration Center 1.7 Pechoraneftegas 5.6 Uralneft 0.1
Geoneft 1.8 Pechoraneftgp 0.1 Uralneftegazprom 1.1
Geotex 1.9 Pechorskaya Energy Co. 0.1 Uralskaya Neft 1
Ideloil 2.2 Penzaneft 3.9 Uralskaya Oil Co. 1.6
Inga 0.2 Petrosakh 2.6 Vanyoganneft 59.5
Ingushneftegazprom 2.3 Pitykh Oil 0.4 Visheraneft 0.1
Institute Rostek 0.1 Preobrazhenskneft 1.6 Vinka 0.005
Irelyakhneft 1.1 Purneftegasgeologia 3.5 Volganeft 2.8
Kabalkneftetopprom 0.1 Purgasdobycha 2.2 Volnovskneft 0.1
Kaliningradneft 1 Quantum Oil 0.2 West Oil 0.003
Kalmeastern 0.6 Rospan International 13.2 White Nights 12.1
Kalmnedra 0.5 Saigas 0.1 Yakutgazprom 1.5
Kalmneft 2.2 Salym Petroleum 0.6 Yangpur 1
Kalmtatneft 0.0003 Samarainvestneft 1.2 Yelabuganeft 0.6
Kara-Altyn 6.6 Samara-Naphtha 3.3 Yenisey 16.5
Khancheyneftegas 11.1 Saneko 5.9 Bogorodskneft 0.8
Khantymansiiskneftegasgeologia 13.4 Saratovneftegeophizika 1.4 Nefteservice 0.7
Kolvaneft 6.2 Selena 0.8 Yugraneft Corp. 7.7
Kondurchaneft 1.1 Serviceneftegas 0.5 Yurkharovneftegas 13.4
Kondurchaneft (Samara) 0.004 Sevosetinneftegazprom 0.2 Yus 0.1
Lenaneftegas 4.6 Sheshmaoil 5.1 ZapadnoAbdulino 0.1
Magma 4.7 Sevosetinneftegazprom 0.2 Zirgan 0.02
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Completed project
One of last projects is the construction of an associated gas processing complex at the Mohtikovsky
oil deposit with a capacity of 20,000,000 m3/year.
Вид на объект сверху (компьютерное моделирование)
Objects designed from computer modeling above
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2009 125
Block of fire heaters
Block of compression Complex of processing
crude-associated gas Electric power station
in gasoline, LPG and
electric power
Block of a cold
Block of pumps
pouring production
Block of preparationeparation
Block of processing
Block of production certification
and storage
Oil.
45
49
51
53
54
118
ё
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New Documentary into Gas Flaring
www.netribution.co.uk/2/index2.php?option=com_content&task=view&id=1202&Itemid=182&pop=1&page=0#
Sunday, 20 May 2007
Apparently 150 billion cubic metres of gas are burnt off every year – enough gas to power the United
States for three months. Even worse - the 390 million tonnes of carbon dioxide released while doing this
is more than the reduction of CO2 emissions from many of the carbon offseting projects of the Koyoto
protocol. Nigeria alone burns off enough gas to power half of Africa for a year. Writer, producer and
director (and co-author of the first funding book), Caroline Hancock, has just completed a documentary
on the subject and apparently almost got shot when shooting in Nigeria. While the screening on BBC
World has passed it may well appear online at some point or be replayed on the channel - and either way
sounds like a pretty important contribution to an ever more urgent problem.
The flaring and venting of Natural Gas is wasting valuable resources and contributing to climate change.
The World Bank's Global Gas Flaring Reduction partnership estimates that 150 billion cubic metres of
gas are burnt off or 'flared' every year - enough to supply the whole of the United States for three months.
Gas flaring and venting also puts 390 million tonnes of carbon dioxide into the atmosphere every year -
more than the reduction of CO2 emissions from all the projects currently registered under the Kyoto
Protocol's Clean Development Mechanism. A new programme in TVE's Earth Report series goes to
Russia and Nigeria to assess the scale of the problem and to examine possible solutions.
For decades national and private oil companies have been burning the gas associated with oil production.
Natural gas is released when oil is produced but is less profitable, especially in countries that lack
sufficient regulation, infrastructure and markets.
"Gas Flaring is a very serious problem today. It's equivalent to 390 million tonnes of CO2 emissions."
says Rashad Kaldany, former head, Global Gas Flaring Reduction partnership.
Although gas flaring continues to be a challenging problem, particularly in developing countries,
capturing gas is not a new idea. Canada introduced legislation in the 1930s and Norway in the 1960s, so
that oil companies could capture and use the gas produced by oil extraction. As a result, both countries
now lead the world in gas capture technologies.
"It's a win-win for everybody, you have the potential to increase utilisation of a premium fuel.it has an
opportunity to provide some poverty alleviation benefits and it reduces a greenhouse gas." Arden Berg,
Alberta Energy and Utilities Board.
The world's top gas flarers, Nigeria and Russia, together burn about 45 billion cubic metres of gas a year.
Despite the fact that gas flaring has been regulated in Nigeria since 1984, the country currently flares off
about 40 per cent of its associated gas - enough to power half of Africa for a year. Yet most Nigerians
have no access to electricity.
Capturing the gas and transporting it to domestic and international markets is difficult and expensive. The
aim of the GGFR partnership is to help Nigeria, and other flaring countries overcome these barriers to
meet the commitment to end gas flaring.
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Small-scale power generation in locations like Bonny Kingdom in the Niger Delta is diverting associated
gas into power distribution, bringing near constant electricity to some areas at affordable prices. Natural
gas is also being liquefied for export to the Atlantic basin.
Russia faces different challenges. Satellite images show that Siberia is home to the largest field of gas
flares in the world. Oil operations are often sited in very remote and inhospitable regions where the
capture and transport of gas is complex and expensive. But even here, there is a business opportunity. One
company is converting gas to methanol in a small plant on site at an oil field. Methanol is much easier to
transport and is sold to the petrochemicals industry. Russian gas and oil giant, Novatek, has just built a
methanol plant in the North Western plains of Siberia.
* * *
Billion Dollar Bonfire was produced with the support of The World Bank's Global Gas Flaring Reduction
Partnership.
TVE and its Partners distribute Earth Report programmes for broadcast and educational and campaigning
use in countries across Africa, Asia & the Pacific, and Latin America & the Caribbean - to schools,
colleges, universities, NGOs, environmental agencies and other 'multiplier' organisations.
Additional Due Diligence on GLOBOTEL HOLDINGS & Globotek
Available in a separate document are:
- List of equipment, building and construction material at Globotek
- In depth CV‘s of management and technical staff at Globotek
- Full set of information disclosure & documents for public company (GBTO)
