IMPROVING ENERGY EFFICIENCY IN PETROLEUM INDUSTRY BY EFFECTIVE UTILIZATION OF ASSOCIATED PETROLEUM GAS IN REMOTE AREAS
Natalia Odnoletkova
Master of Science thesis
KTH Royal Institute of Technology School of Industrial Engineering and Management Energy Technology 2016 SEE-100 44 STOCKHOLM
2016
Master of Science Thesis EGI_2017-0019 MSC EKV 1180
Improving Energy Efficiency in Petroleum Industry by Effective Utilization of Associated Petroleum Gas in Remote Areas Odnoletkova Natalia
Examiner Supervisor Andrew Martin Vladimir Kutcherov Valery Bessel Approved Commissioner Contact person 02.11.2016 KTH Royal Institute of Alexey Lopatin Technology Gubkin Russian State University of Oil and Gas
ABSTRACT
In this thesis the analysis of the oil and gas industry was carried out in terms of possibilities of improving its energy efficiency and carbon emission reduction potential. The largest potential is concentrated in pipeline transportation and petroleum extraction (upstream) sectors. Different possibilities of improving energy efficiency in upstream sector were analyzed, as this sector has large energy saving and energy efficiency improving potential due to effective associated petroleum gas (APG) utilization. Calculation model of application of different as novel, as already existing APG utilization methods for remote oil fields was proposed, as remote oil fields especially face to the problem of absence of infrastructure, reliable energy supply and effective APG utilization methods. Calculation was conducted for three APG utilization methods on the remote oil fields: INFRA GTL conversion of APG into synthetic oil, the use of Capstone turbines for APG utilization, and comparison of these two effective methods with APG flaring. Developed calculation model can be used to give fast initial estimate of economic viability of using particular APG utilization and
ii energy supply method and carbon emission reduction potential, depending on oil field parameters (gas/oil ratio, energy supply, etc.)
Keywords: energy efficiency, petroleum industry, upstream, associated petroleum gas, remote oil fields, gas-to-oil ratio, flaring
iii
Master of Science Thesis EGI_2017-0019 MSC EKV 1180
Improving Energy Efficiency in Petroleum Industry by Effective Utilization of Associated Petroleum Gas in Remote Areas Odnoletkova Natalia
Examinator Handledare Andrew Martin Vladimir Kutcherov Valery Bessel Godkänt Uppdragsgivare Kontaktperson 02.11.2016 KTH Royal Institute of Alexey Lopatin Technology Gubkin Russian State University of Oil and Gas
SAMMANFATTNING
I denna avhandling analysen av olje- och gasindustrin genomfördes i form av möjligheter att förbättra sin energieffektivitet och koldioxid utsläppsminskning potential. Den största potentialen är koncentrerad till transport pipeline och petroleumutvinning (uppströms) sektorer. Olika möjligheter att förbättra energieffektiviteten i uppströms sektorn analyserades, eftersom denna sektor har stor energibesparing och energieffektivitet förbättra potential på grund av effektiv associerad petroleumgas (APG) utnyttjande. Beräkningsmodell för tillämpning av olika som roman, såsom redan existerande APG utnyttjandemetoder för fjärroljefält slogs, som avlägsna oljefält speciellt ansikte mot problemet med frånvaron av infrastruktur, tillförlitlig energiförsörjning och effektiva APG utnyttjandemetoder. Beräkning utfördes under tre APG utnyttjandemetoder på de avlägsna oljefält: INFRA GTL omvandling av APG till syntetisk olja, användning av Capstone turbiner för APG utnyttjande, och jämförelse av dessa två effektiva metoder med APG fackling. Utvecklade beräkningsmodell kan användas för att ge snabb initial uppskattning av ekonomiska bärkraften för användning särskilt APG
iv utnyttjande och energiförsörjning metod och kol potential att minska utsläppen, beroende på oljefältsparametrar (gas / oljeförhållande, energiförsörjnings, etc.)
Nyckelord: energieffektivitet, petroleumindustri, uppströms, associerad petroleumgaser, avlägsna oljefält, gas-till-olja-förhållande, fackling
v PREFACE
This report documents my Master Thesis in Sustainable Energy Engineering at KTH Royal Institute of Technology. The work has been carried out at Gubkin Russian State University of Oil and Gas in the period from September 2015 till October 2016. First of all, I would like to thank my master program supervisors Prof. Vladimir Koutcherov from Royal Institute of Technology (KTH) and Prof. Alexey Lopatin from my home Gubkin University of Oil and Gas for giving me opportunity to conduct this research and for their support during all the period of my education and precious comments, suggestions, and guidance throughout my thesis work. Specially, I would like to thank my thesis supervisor Prof. Valery Bessel for his help and innovative ideas in the field of Sustainable Energy, which helped me to conduct this research work. Also, I am grateful to prof. Kostantin Shotidi from Gubkin University who provided me valuable information regarding energy consumption supply schemes of the oil fields and data for Figure 3.1 and Table 3.2. I also convey my thanks to Prof. Vladimir Mordkovich who is Science Director of Infra Technology LLC for consulting me concerning innovative GTL Infra small scale plant parameters and operation scheme. I would like to thank my friends and fellow students in KTH and Gubkin University where I had the pleasure to meet and get to know such interesting, versatile, and diverse people. Finally, I would like to express my thanks and appreciation to my parents for their continuous support and invaluable help.
vi TABLE OF CONTENTS
NOMENCLATURE ...... ix
LIST OF FIGURES ...... xii
LIST OF TABLES ...... xiii
INTRODUCTION ...... 1
CHAPTER 1. OIL AND GAS SECTOR IN RUSSIA ...... 4
1.1 Oil and gas production in Russia ...... 7
1.2 Eastern Siberia ...... 8
1.3 Selection of the energy scheme for the remote small scale fields ...... 10
CHAPTER 2. ASSOCIATED PETROLEUM GAS UTILIZATION FOR GENERATION OF HEAT, POWER, AND SYNTHETIC OIL PRODUCTION ...... 13
2.1 APG conversion to synthetic fuel technologies ...... 22
2.2 Autonomous power station on the microturbines basis ...... 31
CHAPTER 3. THE SELECTION OF APG UTILIZATION AND ENERGY SUPPLY METHOD FOR THE “CONDITIONAL” OIL FIELD ...... 36
3.1 Technical assessment of different operating methods of the “Conditional” oil field with 50 m3/m3 gas/oil ratio ...... 40
3.1.1 APG flaring. Energy supply is from diesel generator...... 40
3.1.2 APG utilization for synthetic oil production and electricity generation to cover oil field energy needs ...... 46
3.1.3 APG utilization on microturbines for electricity generation to cover oil field energy needs ...... 52
3.2 Technical assessment of different operating methods of the “Conditional” oil field with 100 m3/m3 gas/oil ratio...... 55
CHAPTER 4. ECONOMIC VIABILITY ESTIMATION OF IMPLEMENTATION DIFFERENT POWER SUPPLY AND APG UTILIZATION WAYS FOR “CONDITIONAL” OIL FIELD IN DEPENDENCE ON GAS-TO-OIL RATIO ...... 66
4.1 Economic viability estimation of implementation different power supply and APG utilization ways for “Conditional” oil field with gas/oil ratio 50 m3/m3 ...... 66
4.2 Economic viabilty estimation of implementation different power supply and APG utilization ways for “Conditional” oil field with gas/oil ratio 100 m3/m3 ...... 75 vii 4.3 Discounted cash flow ...... 80
CONCLUSION AND FUTURE WORK ...... 83
BIBLIOGRAPHY ...... 86
viii NOMENCLATURE
Abbreviations APG Associated Petroleum Gas GTL Gas-To-Liquid (Technology) USD United States Dollar GDP Gross Domestic Product GHG Greenhouse Gas GWP Global Warming Potential ESPO East Siberia – Pacific Ocean (Pipeline) GOR Gas/Oil or Gas-to-Oil Ratio NGL Natural Gas Liquids STF Syngas-To-Fuel SMR Steam Methane Reforming ATR Autothermal Reforming POX Partial Oxidation FT Fischer-Tropsch FBP Final Boiling Point LPG Liquefied Petroleum Gas COP Coefficient Of Performance RPM Rotations Per Minute NPV Net Present Value RUB Russian Rubble CAPEX Capital Expences t Tonne (metric ton) Mtoe Million tones oil equivalent mb/d Million barrels per day Mt Million tones
ix km Kilometer m3 Cubic meter kg/kmol Kilogram per kilomole bbl/d Barrels per day dB Decibel kW Kilowatt MW Megawatt V Volt A Ampere Hz Hertz ppm Parts per million mmHg Millimeters of mercury Mm3 Million cubic meters Kt Thousand tones (kilotone) Tm3 Thousand cubic meters MWh Megawatt hours L Liter h Hour kL Kiloleter (thousand liters) m million
Notations
ρoil Oil density under reservoir conditions
ρd.oil Degassed (gas-free) oil density 0 ρAPG Associated gas density value at 20 C and 760 mmHg G Gas/oil ratio
Vg i Annual associated gas production volume
Voil i Annual oil production volume i Year of exploitation
Vf i Annual fluid production x k Mass fraction of water in recovered fluid
Np i Number of production wells in i exploration year
Nw i Number of water injection wells in i exploration year
Vfw i Annual flood water volume
Gsp Specific fuel consumption of a diesel generator
Vd1 i Annual diesel fuel consumption for electricity generation for the first exploitation method of the oil field
Vd2 i Annual diesel fuel consumption for electricity generation for the second exploitation method of the oil field
Vd3 i Annual diesel fuel consumption for electricity generation for the third exploitation method of the oil field
Pcons i Annual average power consumption of the oil field
Econs i Annual electricity consumption of the oil field
Vsf i Annual synfuel production 3 Gsf Synfuel production per 1000 m utilized APG 0 ρsf Synfuel density value at 20 C and 760 mmH
Ep i Electricity production by the plant
Ei The difference between energy consumption and energy provided by the plant p Power generation by GTL plant for external use per 1Mm3 utilized APG annually
tp Number of operating hours per year
xi LIST OF FIGURES
Figure 1.1 – Energy intensity of GDP, 2015...... 4
Top ten the most energy intensive countries [2]...... 4
Figure 1.2 – Main oil and gas regions on the climate map of Russia [11] ...... 7
Figure 1.3 – Oil production by region, Mt [14] ...... 8
Figure 1.4 – Eastern Siberia - Pacific Ocean pipeline (ESPO) [13] ...... 9
Figure 2.1 – Gas-to-oil ratio in Russia in 2010-2014 [19, p. 366] ...... 13
Figure 2.2 – APG Production and use in Russia [19, p. 367] ...... 15
Figure 2.3 – Map of Russia by Federal Districts [23] ...... 16
Figure 2.4 - Oil production and APG flaring in Russia by Federal districts ...... 17
[24, p. 622], [22, p. 19] ...... 17
Figure 2.5 – Average Gas-to-oil ratio in four largest oil producing federal districts. Calculated on the basis of Rupec data on APG production [25] and Rosstat data on oil extraction by regions in 2013 [24, p. 622] ...... 18
Figure 2.6 – APG flaring in Russia by Federal Districts [22, p. 19] ...... 18
Figure 2.7 – APG flaring in Russia in 2010-2012 [26], [19, p. 366], [27] ...... 19
Figure 2.8 – APG Utilization Level in Russia in 2009-2014 [19, p. 366], [26] ...... 21
Figure 2.9 – APG Utilization Level in Russia by districts in 2010-2015 [28] ...... 21
Figure 2.11 - GTL plant on remote oil field scheme ...... 29
Figure 3.1 – Average annual power consumption of the “Conditional” oil field ...... 41
Figure 3.2 – The comparison of different exploitation and energy supply methods for “Conditional”oil field with gas/oil ratio 50 m3/m3 ...... 54
Figure 3.3 – The comparison of different exploitation and energy supply methods for “Сonditional» oil field with gas/oil ratio 100 m3/m3 ...... 63
xii LIST OF TABLES
Table 2.1 – Comparative characteristics of Fischer-Tropsch processes [39] ...... 29
Table 2.2 – Technical parameters of Capstone microturbines basic models [32] ...... 34
Table 3.1 – APG utilization and power supply methods for the “Conditional” oil field ...... 37
Table 3.2 – Major “Conditional” oil field exploration parameters...... 38
Table 3.3 – Major technical specifications of the diesel power plant Wilson P1875E1 [43] .....42
Table 3.4 – Diesel fuel consumption for the first exploitation method of the “Conditional” oil field with gas/oil ratio 50 m3/m3 ...... 43
Table 3.5 – Greenhouse gas emissions estimation for the first exploitation method of the “Conditional” oil field with gas/oil ratio 50 m3/m3 ...... 45
Table 3.6 – Technical analysis of the second exploitation method of the “Conditional” oil field with gas/oil ratio 50 m3/m3 ...... 49
Table 3.7 – Greenhouse gas emissions estimation for the second exploitation method of the “Conditional” oil field with gas/oil ratio 50 m3/m3 ...... 51
Table 3.8 – Technical analysis of the third exploitation method of the “Conditional” oil field with gas/oil ratio 50 m3/m3 ...... 52
Table 3.9 – Greenhouse gas emissions estimation for the second exploitation method of the “Conditional” oil field with gas/oil ratio 50 m3/m3 ...... 54
Table 3.10 – Greenhouse gas emissions estimation for the first exploitation method of the “Conditional” oil field with gas/oil ratio 100 m3/m3 ...... 56
Table 3.11 – Technical analysis of the second exploitation method of the “Conditional” oil field with gas/oil ratio 100 m3/m3 ...... 58
Table 3.12 – Greenhouse gas emissions estimation for the second exploitation method of the “Conditional” oil field with gas/oil ratio 100 m3/m3 ...... 60
Table 3.13 – Technical analysis of the third exploitation method of the “Conditional” oil field with gas/oil ratio 100 m3/m3 ...... 61
Table 3.14 – Greenhouse gas emissions estimation for the second exploitation method of the “Conditional” oil field with gas/oil ratio 100 m3/m3 ...... 62
xiii Table 3.15 – Greenhouse gas emissions during project life cycle 21 years for different power supply methods and GOR, in t CO2 equivalent ...... 64
Table 4.1 – Calculation of costs for the first exploitation method of the oil field with gas-to-oil ratio 50 m3/m3 ...... 69
Table 4.2 – Calculation of costs for the second exploitation method of the oil field with gas-to- oil ratio 50 m3/m3 ...... 71
Table 4.3 – Calculation of revenue for the second exploitation method of the oil field with gas- to-oil ratio 50 m3/m3 ...... 73
Table 4.4 – Calculation of costs for the third exploitation method of the oil field with gas-to-oil ratio 50 m3/m3 ...... 74
Table 4.5 – Calculation of costs for the first exploitation method of the oil field with gas-to-oil ratio 50 m3/m3 ...... 76
Table 4.6 – Calculation of costs for the second exploitation method of the oil field with gas-to- oil ratio 50 m3/m3 ...... 77
Table 4.7 – Calculation of revenue for the second exploitation method of the oil field with gas- to-oil ratio 50 m3/m3 ...... 78
Table 4.8 – Calculation of costs for the third exploitation method of the oil field with gas-to-oil ratio 50 m3/m3 ...... 79
Table 4.9 – Discounted cash flow ...... 81
xiv INTRODUCTION
Today Russian Federation takes the first place in the world in terms of associated petroleum gas (APG) flaring. Among the reasons are the following factors. Traditionally, large oil production fields are supplied by energy from high-voltage transmission lines. Low electricity prices at domestic market make unprofitable building complexes for effective APG utilization for electricity production. Building additional pipeline for transporting APG from the oil field to the refinery require huge capital investments. The second factor is absence of appropriate technologies and experience in associated gas utilization for medium and small scale production facilities. These facilities are commonly supplied by energy from autonomous diesel generators. The use of traditional power generation equipment (gas turbines) for APG utilization has several difficulties, such as low efficiency at part load and stringent requirements for gas quality, what calls for the need of gas pre-treatment facility. This, in turn, increases the capital and operating equipment costs. Another effective APG utilization solution is conversion of associated gas into high-quality synthetic oil. This technology is known as Gas-To-Liquid, or GTL. However, the possibilities for this technology application for remote oil fields almost have not been studied so far due to absence of economical viable commercialized medium and small scale GTL plants and experience in its exploitation. The relevance of the proposed research It should be noted, that today the situation in Russian oil and gas industry is gradually changing: new oil production fields are mostly medium or small, and they are situated in remote underpopulated areas with severe climate conditions and absence of infrastructure and transport connection. This complicates the construction of transmission lines for electricity supply and fuel delivery on site. For those oil fields already in operation in Russia the intensification of the production occurs and the energy needs for such oil fields are growing as these 1 fields are becoming more energy intensive. Russian government strategy is aimed for energy efficiency improvement and much attention has been given to an effective APG utilization and connected problems, such as carbon emissions and other pollutants reduction. Growing taxes and fines for ineffective APG utilization (what is flaring) and deteriorating ecological situation in the oil production regions force petroleum companies to increase the share of processed APG significantly and find new sustainable methods of such viable energy source utilization. Moreover, associated gas production increases each year and new oil production fields situated in Eastern Siberia have much higher gas/oil ratio than average value in the country (see Figure 2.5). This makes appropriate environment for new technologies development and energy saving improvements in upstream petroleum sector. Thus, it can be concluded that associated petroleum gas is becoming very attractive source of energy and by its effective utilization in a great extent can be fulfilled the growing energy needs of the Russian oil and gas sector and significantly decreased CO2 and methane emissions. The developing of new energy sources is becoming more relevant nowadays for Russian petroleum industry. Remote oil fields require new innovative energy scheme of autonomous heat and power production using available local fuels. Nowadays new perspective APG utilization technologies are developing intensively, and these utilization methods can help to fulfill the energy needs of the oil field. The latest research in turbomachinery is aimed to turbines optimization for diverse exploitation conditions and the possibilities to use low quality fuels. Moreover, some of the commercialized GTL small scale plants are starting to appear at the market. These technologies are new and diverse; many of them just now start to be used in the industry. Hence, they are very interesting in terms of analysis of their energy efficiency and estimation of emission reduction in case of particular technology application.
2
The aim of the thesis The aim of this research work is analytics of the APG production and use in Russia and suggesting different APG flaring problem solutions, which can be effectively implemented on the remote oil fields. Research objectives include The analysis of current APG production and use in Russia and finding the reasons and concerns of associated gas flaring, as well comparison of already existing and novel technologies in APG utilization, which can be applied for the remote oil fields, and conduction of the technical and economic analysis of their effective implementation for the remote oil fields. Also, the assessment of the potential of carbon emission reduction in case of particular technology application. Scientific novelty of the work The comparison analysis of the described in this work modern technologies implementation for the remote oil fields has not been conducted yet. Also, current situation in APG flaring in Russia is well described. The calculation model of the different APG utilization methods implementation (novel GTL technology in comparison with other existing utilization methods) has been developed for the “Conditional” oil field and can be successfully applied for any other oil facility in dependence on oil field parameters (gas/oil ratio, energy consumption, etc.) for the fast economical and technical evaluation, as well as emission reduction potential and fuel consumption in case of particular APG utilization technology application. The calculation has been conducted for three different associated gas utilization methods: novel GTL INFRA.xtl plant (such type of calculation has been conducted for this technology for the first time), Capstone micro turbines, and the comparison of these two effective methods with APG flaring.
3 CHAPTER 1. OIL AND GAS SECTOR IN RUSSIA
Solution of the energy efficiency problems now stands in the forefront of the Russian national agenda [1]. Economy growth to a great extend can be fulfilled by increasing of its productivity. In particular, by increasing production per unit of energy consumed (what means increasing energy efficiency, one of the most important ways to enforce Russian economy growth). Russian Federation is the world leading country in terms of energy intensity [2]. According to the statistical agency Enerdata [2], in 2015 in order to produce 1 USD of gross domestic product (GDP) Russian economy consumed 0.34 kg of the oil equivalent. This value is 50% higher than in China and two times higher than in the United States (see Figure 1.1).
Figure 1.1 – Energy intensity of GDP, 2015. Top ten the most energy intensive countries [2]
Oil and gas sector is the main element of the Russian economy. The share of petroleum is more than half of the total Russian export, meanwhile the share of crude oil in 2015 amounted to 26%, natural gas - 14% in money equivalent (according to the UN Comtrade database [3]). Oil and gas industry is accounted to 4 more than third of the total Russian budget income (mainly due to the oil and gas extraction and export taxes [4]) and considerable amount of the Russian production. This results from high production in the industry – more than 10 million barrels daily (13% the world total oil production) and more than 600 billion cubic meters of the natural gas per year (18% the world total production) in 2014 [10]. Energy efficiency of the petroleum industry very largely influences Russian economy development. As the major industry in Russian economy, petroleum sector is one of the biggest energy consumers. It is accounted to the 12% of the total primary energy consumption in Russia [5, p. 62]. Carbon emissions are tightly connected to the energy efficiency problem. The share of greenhouse gas (GHG) emissions in this sector is amounted to 23% of the total Russian GHG emissions. Methane leaks are not only the wasting of valuable natural resource, but huge ecological damage. Natural gas leaks (despite its minor mass share) are amounted to 40% of the total GHG emissions of the sector [5, p. 62]. This is due to the fact that global warming potential (GWP) of methane is 21 times higher than the potential of CO2 [6, p. 22]. Energy losses and GHG emissions occurs almost at all oil and gas production stages. However, the largest energy consumers are gas transportation system and oil extraction. But these sectors have also the largest resource savings potential. Natural gas industry spends up to 10% of the produced gas to fulfill its own energy needs, and more than 90% of this value is consumed by natural gas transportation system [7, p. 7]. Natural gas transportation energy needs are usually exceed initially planned values. This occurs mainly due to gas pipelines deterioration, worn out compressor stations equipment, and absence of appropriate technological optimization of the pipeline working regimes. Also, the proper attention is not given to the real technical condition of the equipment, which is highly different from the initial specifications. Natural gas consumption by pipeline transportation is as follows: fuel gas – 81.6%, other needs – 9.0%, gas
5 leakages – 9.4% [7, p. 41]. Thus, in pipeline gas transportation gas losses are accounted for approximately 0.86% of the total amount of natural gas production, what is equal to more than 5 billion cubic meters annually. According to McKinsey&Co, total annual natural gas losses during pipeline transportation, gas distribution and transmission are equal to 13 billion cubic meters, what is enough to support all natural gas needs of St. Petersburg and its region [5, p. 62]. Total energy consumption by pipeline transportation is 28.7 Mtoe (26.2 Mtoe is supported by natural gas consumption, and 2.2 Mtoe is electricity), what is amounted to 7% of the total Russian primary energy consumption [8]. Energy consumption by the pipeline transportation system is almost equal to the total energy consumption of the whole Sweden and two times more than New Zealand annual energy consumption (according to the International Energy Agency [8], 2015). Gas losses during its transportation are 22% higher than in US per unit of gas transported [5, p. 62]. This is due to considerable worn out of the pipelines and equipment, absence of appropriate technological optimization of the pipeline working regimes. Moreover, low natural gas prices as a fuel source make unprofitable the use of energy efficient technologies and new equipment commissioning. In this work it is shown that oil and gas sector in Russia has a great energy saving and emission reduction potential. Today Russian government establishes measures and policies aimed to improving energy efficiency of the petroleum industry [1], [9], mainly due to effective APG utilization, pipeline equipment replacement, and modernization of the refineries. Upstream sector (petroleum extraction) is very interesting in terms of its energy efficiency analysis, as it has a great energy saving potential due to effective APG utilization possibilities. Technologies that can be implemented for effective APG utilization are diverse, new, and just now start to be applied in Russian petroleum industry. Hence, these technologies are interesting in terms of conducting technical and economical assessment and analysis of their effective implementation in the industry.
6
1.1 Oil and gas production in Russia
According to OPEC, Russia is the second largest natural gas producer in the world after USA. In 2014 natural gas production in Russia amounted to 642.917 billion cubic meters, what is equal to 18.03% the world production [10]. Also, Russia is the leading country in terms of oil production. In 2014 the share of Russian Federation in world crude oil production amounted to 13% (10.221 mb/d, and it is more than 500 Mt annually), what is almost equal to the share of Saudi Arabia [10]. The main oil and gas resources are mainly concentrated in Western Siberia (Urals Federal District) region (Figure 1.2), but the production in this region has started to decline (Figure 1.3, 2.4), as old fields that have been already in operation
Figure 1.2 – Main oil and gas regions on the climate map of Russia [11]
7 for decades now have oil and gas extraction decrease, and these oil fields are becoming more energy intensive. Russian government established “2020 energy strategy” [1]. It need to be said, that one of the aims of this strategy is diversification of the oil and gas production regions [1, p.17]. The role of Western Siberia as a main oil and gas production region will decrease and Eastern Siberia and Far East (Figure 1.2) will play more and more important role in the future. It is expected, that till 2020 the Western Siberia oil production is going to drop slightly till 290-315 Mt per year [12], while other regions, such as Eastern Siberia, will expand their productivity. Also, perspective oil and gas regions are Sakhalin Island,
Figure 1.3 – Oil production by region, Mt [14]
Caspian, Barents and Baltic Sea offshores, and Timan-Pechora. These regions are situated in underpopulated areas with severe climate conditions (Figure 1.2) and lack of infrastructure. Hence, new oil fields situated in described regions require new innovative energy scheme in order to meet these conditions and provide reliable electricity generation methods, using available local fuels.
1.2 Eastern Siberia
More than half of the total oil production in Russia comes from Western Siberia. However, as it has been already noted, oil extraction in this region starts to decrease. The answer for the question which region can replace Eastern Siberia in
8 terms of petroleum production was already known decades ago. As early as 1974, USSR minister of Petroleum Industry Valentin Shashin noted that such region can be Eastern Siberia [15]. Development and exploration of the new territory is an enormous challenge, that require huge capital investment and new technical and engineering solutions as weather and climate conditions of this region are far more severe than at western part of Siberia. Moreover, main oil and gas objects are remote considerably from the nearest localities and towns, what makes the construction and further exploitation process of the oil fields much harder. Several years ago, in December 2009, the first stage of the Eastern Siberia - Pacific Ocean pipeline (ESPO pipeline) with annual capacity of 30 million tones and total length of 2694 km was put into operation. The first stage is named ESPO- 1 and connects Taishet and Skovorodino (Picture 1.4). In May 2010 the
Figure 1.4 – Eastern Siberia - Pacific Ocean pipeline (ESPO) [13] construction of the second stage of the pipeline (ESPO-2) started. ESPO-2 pipeline connects Skovorodino and oil-loading seaport Kozmino near the town of Nakhodka. It was commissioned in December 2012. Its length is 2046 km, and at the time of putting in operation the annual capacity amounted to 30 million tones. In 2014 works had been carried out on increasing annual capacity of the ESPO-1 9 up to 58 million tones. “Transneft” – exploiting company of the pipeline – is planning to increase till 2020 the capacity of ESPO-1 up to 80 million tones and ESPO-2 up to 50 million tones annually. Skovorodino - the People‘s Republic of China border is a branch pipeline of ESPO (Figure 1.4), which was put in operation in August 2010. It has length of 63.4 km and initial capacity amounted to 15 million tones annually. In 2015 this value had been increased till 20 million tones [16], [17]. Growth of oil production in this region in order to meet planned export volumes by ESPO pipeline makes good prerequisites for comprehensive solutions of energy efficiency problems. Also, increasing of oil production will have positive effect on new technologies development, including effective APG utilization and decreasing of capital investments for implementing new technologies on the Eastern Siberia territory. Upstream oil and gas sector energy problems will not lose their relevance in the future because of increase of oil production in remote areas with severe climate conditions. This sector has large potential for increasing its energy efficiency and energy savings improvements due to effective APG utilization solutions, as APG is local, abundant, and cheap source of energy.
1.3 Selection of the energy scheme for the remote small scale fields
A great attention should be paid to the selection of the energy scheme for the oil field, as all project stages from engineering and procurement to capital investment and future profitability are dependent on energy supply method. Different energy supply and APG utilization methods will be discussed in the next chapter. Electricity on the oil field is mainly used for pump drives and oil processing facilities where dehydrating and desalting of oil are conducted. Also, significant amount of energy (diesel fuel) is consumed by vehicles. Large oil fields are planned to be exploited for many decades, and they require huge amount of energy. Hence, it can be economically viable to supply 10 these oil fields with high voltage transmission lines and build additional transportation system for APG sending from the oil field to the refinery. However, for medium and small scale oil facilities such infrastructure costs are usually ineffective, especially if we consider the fact that most of the new oil fields are situated in the remote areas with severe climate conditions. Centralized power supply has two important disadvantages. The first is the risks of uninterrupted electricity supply due to challenging weather conditions. The second disadvantage is the problem of effective APG utilization as centralized power supply doesn’t imply the use of available local fuels. At the moment reliable energy supply problem is most relevant for small and medium oil production fields with relatively low energy consumption volumes. Power supply for such fields is traditionally from autonomous diesel generators. However, fuel transportation for the remote areas is very challenging, especially when transportation process is complicated by unfavorable climate conditions. The fuel is often delivered by helicopters (which are the main means of transportation in these regions) and the price of diesel fuel during its transportation can rise up to several times. Moreover, with Russian Federation Government decree № 1148 of November 8 2012 “On the calculation of fines for emissions to air formed through flaring or venting of associated petroleum gas” [9], the problem of efficient use of APG have risen significantly as, according to the Decree, no more than 5% of the total APG output can be flared. Moreover, government establishes heavy fines for those oil producers who breake the limit of APG volume. These two problems – reliable energy supply for the oil field and efficient APG use can be solved together. When APG is utilized for electricity production either power shortages or power surplus can be observed. Let us discuss these following options: APG excess for electricity production on the all stages of the oil field exploitation;
11 Lack of APG on some stages and excess on other stages of the exploration; APG amount is not enough to cover oil field electricity needs at all exploration stages. Each of these described situations determines which energy supply and APG utilization scheme to choose. For the first option when APG abundance is observed, the possible solution is APG conversion to synthetic fuel and its use for oil field needs or sending from the oil field to other consumers. For the second option APG reinjection to the reservoir can be a good solution in order to distribute associated gas extraction it time, support reservoir pressure, and aid oil recovery. Finally, when lack of APG for power production is observed, good option for remote oil fields is bifuel power systems or steam installation, which can operate using available local fuels, for instance, associated gas or extracted oil. Energy consumption of gas fields is much less than of oil fields as natural gas comes to the surface by reservoir pressure while for oil extraction the reservoir pressure is not enough, and extraction pressure is created artificially using pumps. Energy is consumed mainly in gas treatment unit. Energy efficiency improvement can be achieved by gas condensate utilization in bifuel systems (natural gas and gas condensate fuel mix) for heat and electricity generation.
12 CHAPTER 2. ASSOCIATED PETROLEUM GAS UTILIZATION FOR GENERATION OF HEAT, POWER, AND SYNTHETIC OIL PRODUCTION
Associated petroleum gas (APG), or associated gas, is a form of natural gas, which is found with deposits of petroleum, either dissolved in the oil or as a free "gas cap" above the oil in the reservoir under high pressure reservoir conditions. [18, p. 1] When oil is extracted the pressure decreases and associated gas separates from the oil. Historically, this type of gas is considered as a waste product from the petroleum extraction industry, so this gas is simply burnt off in gas flares. This process is called flaring and when this occurs the gas is referred to a flare gas. Gas/oil ratio (GOR) is the amount of associated petroleum gas, in m3 (standard conditions, atm. pressure, 20 oC), released from the 1 m3 or tone extracted oil (under the same conditions). The gas factor value can reach 800-900 m3/m3, but average value is 147.7 m3/tone (about 125 m3/m3) for the oil fields that are currently in operation in Russia (Figure 2.1).
Gas/Oil Ratio in Russia in 2010-2014, m3/tonne 160 140 120 100 80 60 40 20 0 2010 2011 2012 2013 2014 Source: Rosstat Figure 2.1 – Gas-to-oil ratio in Russia in 2010-2014. Data source: Rosstat [19, p. 366]
13 In case reservoir pressure is higher than saturation pressure (i.e. no gas release from the oil in the reservoir), GOR remains constant and equal to initial gas content in the oil reservoir. GOR can be also influenced by the operation regime of the oil field. In case of water drive regime (when water pressure supports the pressure in the reservoir) GOR remains constant during all exploration period. In case of gas head exploration conditions, GOR increases significantly on the final stages of the oil field exploration [20]. As it can be seen from the graph (Figure 2.1), GOR in Russia steadily increases each year, and APG production grows as well (Figure 2.2) despite the fact that oil production in the country remains almost stable (Figure 2.4). But what is the reason for that? Today oil production (Figure 2.4) in Russia shifts to the North and East. As it have been already noticed before, oil production in Western Siberia (Urals Federal District, see Figure 2.3) today slightly declines while Eastern Siberia (Siberian Federal District) increases oil extraction. Gas/oil ratio in Siberian Federal District is very high compared to other regions: it this area more than 200 m3 of APG is released from the tone of oil extracted (Figure 2.5). Today we can observe that the share of Siberian Federal District in APG flaring amounts to 48% while oil production in this region is only 9% (Figure 2.4) To sum up, the reasons for that are increasing production in east regions of Russia, which have high gas/oil ratio, relatively low APG effective utilization level in the region, especially on remote oil fields, and significant improvements of APG utilization at traditional oil regions. This fact makes the problem of effective APG utilization in remote areas more relevant each year. The most used APG utilization ways are (Figure 2.1): Sending of APG from the oil field for its future processing. APG is usually separated to stripped gas (methane, or general natural gas) and NGL (natural gas liquids, which are commonly consist of propane, butane and other heavy gas fractions). Further, natural gas can be used for the wide range of needs, while NGL are commonly used as a raw material in
14 chemical industry. In Russia NGL are usually purchased by chemical companies for polyethylene and polypropylene production. The use of APG for oil fields own needs, which include: o significant part of associated gas can be pumped to the reservoir in order to support extraction pressure (gas head exploration) o as a fuel for steam power plants for generation of heat and electricity o after gas treatment as a fuel for gas turbine installations o GTL conversion of associated gas into high quality synthetic oil or diesel fuel, which can be further used for support oil field energy needs in fuel or sending it from the oil field for other consumers. GTL plant also produces significant amount of heat (which can be used for oil field needs and electricity production). However, there is almost no experience of this method application in Russia so far. APG flaring. Today considerable amount of APG (more than 50 %, see Figure 2.2) is sent from the oil field. About 80% of that value is sent to the gas processing plant and about 20% to other consumers. [21, p. 13] Also, significant share of APG is used for oil field needs.
Figure 2.2 – APG Production and use in Russia. Data source: Rosstat [19, p. 367]
15 However, new oil fields, which are mainly situated in remote areas with severe climate conditions, usually have no infrastructure to send gas from the oil field. Moreover, huge capital investments in gas utilization equipment not at all times pays off in the future as exploitation and transportation of the equipment costs are much higher than for conventional oil fields. So, petroleum companies, which are operating these oil fields, usually don’t take the risk of investment in effective APG utilization technologies. And this is the main reason why the share of flared APG in remote areas is so significant. According to the Russian Federal State Statistic Service [19, p. 367], [22, p. 19] in 2008 Ural Federal District (Figure 2.3, 2.6) APG flaring accounted to 11 billion cubic meters or 80% of the total amount flared APG in Russia. Nowadays, however, the situation has gradually changed. For the past several years Siberian Federal District (Figure 2.3) takes the 1st place in terms of APG flaring amount. In 2014 its share was 48% and total flared gas amounted to 5.2 billion cubic meters while the share of Ural Federal District shrinked till 27% (2.9 billion cubic meters), see Figure 2.4.
Figure 2.3 – Map of Russia by Federal Districts [23]
16 Oil and gas condensate production in Russia by Federal districts in 2010-2014, Mt 600
500 Others
400 Northwest Federal District
300 Siberian Federal District
200 Volga Federal District
100 Urals Federal District
0 2010 2011 2012 2013 2014
Oil and gas condensate APG flaring by federal districts in production by federal districts in Russia in 2014, % from total APG Russia in 2014, % from total oil output production
4% 7% 8% 5%
9% 13% 48%
57% 22%
27%
Source: Rosstat
Figure 2.4 - Oil production and APG flaring in Russia by Federal districts. Data source: [24, p. 622], [22, p. 19]
17 Average Gas Oil Ratio in four largest oil producing federal districts, m3/tonne
250
200
150 Urals Federal District Volga Federal District Siberian Federal District 100 Northwest Federal District
50
0
Figure 2.5 – Average Gas-to-oil ratio in four largest oil producing federal districts. Calculated on the basis of Rupec data on APG production [25] and Rosstat data on oil extraction by regions in 2013 [24, p. 622]
Figure 2.6 – APG flaring in Russia by Federal Districts [22, p. 19]
18 New oil production fields are mainly situated in remote areas of Siberian Federal District with absence of infrastructure for effective APG utilization while existing oil fields in Urals Federal District had already developed infrastructure, and there are gas chemical plants that are available to purchase associated gas for its further processing. Moreover, oil and associated gas production in Urals Federal District declines. Hence, in this area APG effective utilization increased significantly for the past years. All countries that produce petroleum face to the problem of effective APG utilization. However, according to the World Bank, Russia takes the first place in the world in terms of gas flaring (Figure 2.7). But two organizations in Russia, who provide data concerning APG flaring, give far more different values than World Bank (see Figure 2.7).
APG flaring in Russia in 2010-2012, billion cubic meters 40
35
30
25
20 Minenergo data Rosstat data* 15 Worldbank (satellite data) 10
5
0 2010 2011 2012
*small enterprises activities were not taken into account
Figure 2.7 – APG flaring in Russia in 2010-2012. Data source: [26], [19, p. 366], [27]
Such enormous difference can be explained by the fact that World Bank data are calculated on the basis of satellite data. This means, all gas flares could be taken into account, including gas flares of chemical, gas processing plants and
19 refineries, and gas condensate flares, which are not referred to APG flares and are not included in Russian statistics. Anyway, even 10-15 billion cubic meters of flared gas is a huge natural resource waste and these values can be compared to the annual natural gas consumption by a typical European country. Russian Federation Government decree № 1148 of November 8 2012 “On the calculation of fines for emissions to air formed through flaring or venting of associated petroleum gas” [9] establishes APG effective utilization level 95% from the total output. So, associated petroleum gas flaring is becoming more costly and unprofitable for the companies due to increased taxes and fines for ineffective APG utilization each year. Hence, petroleum companies are actively implementing new methods for APG utilization. And the results of the government policies can already be seen: APG level of effective utilization increases each year (Figure 2.8 and 2.9), and APG flared amount decreases even though its production rises (Figure 2.2). Significant growth was achieved in Siberian Federal District where effective APG utilization level tripled during the period of three years from 2012 till 2015 (Figure 2.9). However, this value is still less than average APG utilization level in the country. Despite the fact that average APG effective utilization grows in Russia each year and this value is about 87-88% (Figure 2.8) in some remote areas APG utilization level, according to official Rosstat statistics [28], is still barely exceeds 50%. For example, in Irkutsk region, which is situated in the north part of Siberian Federal District, APG effective utilization in 2015 amounted to 36.9% only. Low APG utilization levels can be observed in Nenetsky Autonomous Region (a northwest part of Northwest Federal District) where this value is 38.2%. But the “leader” in the share of flared APG is Sakha Republic (Far East Federal District) where only 12.3% of APG in 2015 was utilized effectively. All three most ineffective regions in terms of APG utilization are situated in severe climate conditions. This calls for the need of new effective technologies of APG utilization that can be implemented in remote areas with unfavorable climate conditions.
20 APG Effective Utilization Level in Russia in 2009-2014, %
100.0 85.5 88.2 90.0 76.3 78.8 80.0 75.5 76.2 83.0 70.0 72.5 74.1 60.0 69.6 68.2 67.7 Rosstat data* 50.0 Minenergo data 40.0 30.0 20.0 10.0 0.0 2009 2010 2011* 2012 2013 2014 s m Figure 2.8 – APG Utilization Level in Russia in 2009-2014 [19, p. 366], [26]
APG effective utilization level in Russia by four largest oil producing federal districts in 2010-2015, %
Urals Federal District Volga Federal District Siberian Federal District Northwest Federal District
100.0 93.8 91.2 92.9 86.6 87.0 90.0 84.2 85.4 84.3 81.9 79.2 78.2 80.0 75.7 76.9 70.0 67.4 61.7 61.5 62.7 59.9 60.0 52.6 50.0 46.3
40.0 33.1
30.0 25.7 24.3 25.5 20.0 10.0 0.0 2010 2011 2012 2013 2014 2015
Small enterprises activities were not taken into account Source: Rosstat
Figure 2.9 – APG Utilization Level in Russia by districts in 2010-2015. Data source: Rosstat [28]
21 In this thesis different APG utilization and oil field energy supply methods are discussed, taking into account remoteness of the oil field and severe exploitation conditions, as it has been shown that these regions are the most vulnerable in terms of APG effective utilization possibilities. The comparison of different APG utilization methods both from environmental and economical point of view is shown in Chapter 3.
2.1 APG conversion to synthetic fuel technologies
In remote areas it is usually hard to send APG from the field. Hence, APG should be treated on site. One of the possible options is associated gas conversion into synthetic oil. The key issue for synthetic fuel production is choice of the process of synthesis gas (syngas) production from methane, which is the main component of the APG, and Syngas-To-Fuel (STF) technology of synthesis gas conversion into high quality fuel, which can be further used as a fuel for diesel generators, cars, and other vehicles on the oil field. The remaining amount of fuel can be sent from the oil field to other consumers (nearby oil fields and villages) or mixed with recovered oil, which is further transported by pipeline from the field. Full process, which is known as GTL (Gas-To-Liquid), includes synthesis gas production (CO and H2), and subsequent production of high-quality diesel, gasoline or other diverse chemical substances, such as methanol, ammonia, and ethylene. GTL technology is proven and has been already used for many decades. However, the possibilities of implementing this technique on small-scale remote oil fields in Russia almost have not been studied so far. In particular, the main problem is relatively small size and output of the plant compared to the traditional large-scale GTL installations and high share of heavy fractions and impurities (such as sulphur and nitrogen compounds) in
22 associated gas. Moreover, for each particular oil field conversion technologies can vary in dependence on gas composition. Also, possible variations of APG composition and production in time need to be taken into account. Main methods of synthesis gas production: 1. The most often used process is steam reforming of methane (SMR):
CH4 + H2O = CO + 3H2 (2.1)
Methane reacts with steam on heterogeneous catalysts, generally at temperature 700-900 0С and 40 bar pressure [33], [34, p. 4]. Steam reforming is an endothermic process, and required energy amount can be supplied by: associated gas combustion (external heating, allothermal process); partly combustion of the feed hydrocarbon products inside the reactor (autothermal process) in accordance with:
СH4 + ½ O2 = CO + H2 (2.2)
2. Autothermal reforming (ATR) is a process of methane conversion to syngas by reacting with steam under deficient oxygen ratio over appropriate catalysts. This type of conversion require 1000-1100 0С temperature and pressure up to 55 bar.
Among the advantages of the ATR and SMR processes is high H2/CО ratio, lower oxygen demand, and less requirements for composition materials of the plant. However, careful treatment of feedstock is essential, especially in removing
H2S. As a feedstock is associated gas, such purification requirements can be very costly as APG contains considerable amount of sulphur and nitrogen components [33], [34, p. 4]. 3. Autothermal methane reforming into synthesis gas under non-catalytic conditions is known as partial oxidation (POX). This technology requires high 23 temperatures up 14000С in order to overcome kinetic limitations. Such temperatures can be obtained by increasing oxygen consumption in the reactor, what in turn causes higher costs of the reaction (due to more oxygen consumption) and more expensive construction materials compared to other methods. Among the other disadvantages of the POX is low conversion
coefficient H2/CО. However, this technology can benefit from its operation flexibility. As a process without catalysts it can be used for syngas production from APG of different composition (for example, with a variable content of higher hydrocarbons, CO2, N2, and H2S).
Low conversion coefficient H2/CО can be increased by including separate water-gas shift reaction step where carbon monoxide reacts with steam over heterogeneous catalysts to form hydrogen and carbon dioxide [34, p. 4]:
CO + H2O = CO2 + H2 (2.3)
After syngas is produced, it should be purified from harmful components, such as H2S, COS, HCN, and others. Synthetic fuel production from synthesis gas: The majority of technologies for synthetic fuel production, which are based on synthesis gas generation, can be divided on two groups: 1. Fischer-Tropsch synthesis. The first group is based on Fischer-Tropsch synthesis. Syngas reacts on heterogeneous catalysts at the temperature 220 – 2300С and 20-25 bar pressure [33, 34]. The mixture of different hydrocarbons with a very board molar mass distribution (saturated, unsaturated, aromatic hydrocarbons) is formed, which is further after multi-stage treatment is used for production of synthetic fuel or other chemical components. Due to complexity of upgrading treatment stages Fischer-Tropsch synthesis is often performed on large-scale GTL-installations. Leaders of the market in FT-
24 technologies are Sasol and Shell. Both companies do not possess small-scale GTL installations, that could be applied on remote oil fields and do not provide FT- technology licenses to other companies. However, there are some companies, such as Rentech, Velocys, Compact GTL, which had already developed FT-synthesis technologies that can be implemented for APG utilization on remote oil fields. However, such technologies have not been commercialized yet [34, p. 4-6]. One of the most innovative FT-processes is INFRA.xtl technology, which was developed by Russian scientists and which can take proper place among APG effective utilization solutions due to its strong profitability and operation simplicity [39]. This technology is discussed in more detail in the following chapters. 2. Methanol production and its conversion into high-quality synthetic fuel over zeolite catalysts (methanol-to-synfuel technology). The first stage of the process is methanol production over copper catalysts at 230-2800С and 50-70 bar, according to the well-established process [34, p. 5], [35], [36]:
CO + 2H2 = CH3OH (2.4)
The following process is methanol conversion into liquid fuels over copper- based catalysts at 350-4200С and 5-10 bar. In dependence on process conditions it is possible to shift reaction to predominant gasoline or diesel formation. “Methanol-to-synfuel” technologies are developed and commercialized by Mobil and Lurgi but only for large-scale installations [37, 38]. Perspective technologies of synthetic fuel production on remote oil fields Novel perspective synthetic fuel production technologies that can be adapted for APG utilization on remote oil fields in small-scale plants are discussed below. The group of Russian researchers from Ukhta State Technical University joint with German side (Technical University Bergakademie Freiberg) have been conducted research of the full GTL production route based on synfuel production
25 technology from Chemieanlagenbau Chemnitz GmbH and its optimization for specific Russian exploitation conditions and market potential of this technology implementation. The interim results of this work were presented in a paper “Utilization of Associated Petroleum Gas at Oil Production Facilities Located in Remote Area for the Generation of Heat, Electricity and Synthetic Liquid Fuel”, which was published in OnePetro database [34, p. 2, 5]. According to the article, new perspective technology of methanol conversion into synfuel was developed by Chemieanlagenbau Chemnitz GmbH as a part of full GTL process. This technology is based on new reactor construction and the use of specially developed tailor-made catalysts. It allows to generate high quality synthetic gasoline, which can be directly used after single distillation step. Technical viability of this method was demonstrated on pilot plant, which has been in operation since 2010 in cooperation with Technical University Bergakademie Freiberg. Due to process simplicity, high efficiency and reduced emission formation, this technology can be easily adopted to synthetic fuel generation in compact GTL-facilities in remote areas. Fischer-Tropsch 4th generation Another very perspective technology is INFRA.xtl, which allows to utilize APG on remote oil fields efficiently and economically viable. According to the official data [39], INFRA.xtl is the 4th generation of Fischer-Tropsch synthesis. Developed technology is cost effective even for small-scale plants. Finally, GTL technology is becoming profitable for oil fields situated in remote areas. Productivity of the catalysts and reactor are much higher than in other industrial GTL installations. This makes Fischer-Tropsch process more effective, decreases capital and investment costs, reduces reactor size and exclude several reaction stages, which are needed for other GTL synthesis technologies. This allows to design economically viable module plants. INFRA technology allows to produce 400 kg of liquid hydrocarbons from 1000 m3 APG consumed and generate power of 200 kW for 1 million m3 APG annual consumption. Half of this value is
26 consumed by the plant and another half is used to fulfill needs of the oil field in electricity [Error! Reference source not found.40]. Key INFRA.xtl advantages [39]: High quality monoproduct – a mixture of light liquid hydrocarbons. The share of light hydrocarbons is 95% (FBP <360°С) in the total output from the Fischer-Tropsch reactor. This, in turn, allows to eliminate hydrocracking and further upgrading stages. Reduction of the Fischer-Tropsch reactor size. Due to high productivity of the catalysts (up to 300 kg/hour of synthetic oil output for 1 m3 reactor volume) reactor size reduction is up to 3 times compared to other industrial Fischer-Tropsch reactors. Versatility. Technology allows to use feedgas of different composition (from dry methane to APG with high molecular weight up to 24 kg/kmol) due to two technological advances: breaking up of heavy hydrocarbons at pre-
reforming stage and H2/CO relation regulation by CO2 feedrate variation (steam/dry reforming). Power generation. High reaction temperature (250°С) allows to use heat for producing power on steam turbine (steam pressure up to 40 bar) to cover energy consumption of the plant and external electricity needs. Efficiency and stability of the catalyst. The catalyst does not contain precious metals, what influences its low cost. Furthermore, slow deactivation results in longer catalyst lifetime up to 2 years. Ecological benefits. Absence of oxygenates eliminates the need in rejection unit. Water from the Fischer-Tropsch reaction is treated minimally in degassing boiler and then is used directly in steam reforming process. Moreover, steam/dry reforming process, which is used in Infra plant, allows
to utilize 75% of the generated CO2. Product benefits include: o Absence of sulphur and aromatics components. o High share of iso-paraffins and olefins. 27 o High cetane number for diesel fuel. o Up to 45% of the product is jet fuel fraction. o Product can be characterized by Shulz-Flory alpha of 0.77. On the Figure 2.10 Infra GTL process is shown in more detail: Associated gas separated from the produced oil goes to the plant. The part of the gas is used to supply heat for the steam reforming reaction, which is highly endothermic, and as well electricity to cover oil field needs is produced. The product of the steam reforming is syngas (carbon monoxide and hydrogen), which is then converted to synthetic oil using Fischer-Tropsch reaction. Synthetic oil is then can be used as a fuel for vehicles, cars, and other local needs. The remaining can be mixed with the oil from the field and sent to the pipeline. General scheme of GTL plant implementation in remote oil fields is shown at Figure 2.11.
Figure 2.10 –Novel INFRA.xtl GTL plant via APG flaring [39]
INFRA.xtl catalysts allow to modify process in order to produce high quality gasoline, diesel or jet fuel. INFRA plant is fully compatible with the existing oil industry infrastructure, processes and technologies, has low capital and operating costs and significantly reduces carbon emissions of the field. The comparison of the INFRA.xtl process and previous 3rd Generation Fischer-Tropsch is shown in Table 2.1.
28
Figure 2.11 - GTL plant on remote oil field scheme
Table 2.1 – Comparative characteristics of Fischer-Tropsch processes [39] 3rd Generation Fischer- Parameters INFRA.xtl Tropsch FT reactor size ( diameter - height, m) Large scale facility (34 000 10.7 × 60 5 × 20 bbl/d)
Small scale facility (300 Not considered 1.0 × 6 bbl/d) economically feasible
Productivity, kg per 1 m3 40–100 270-300 reactor volume in one hour
Additional reactors for Necessary Not needed hydrocracking and upgrading
Diesel + Naphtha + Product LPG + oxygenate + Monoproduct lubricant precursors
29 Table 2.1 (cont.) Product yield (kg per 1 000 390–440 (function of 390–440 (function of m3 of gas consumed) heat utilization) heat utilization)
Product fractions (weight %)
<40 °C 10 — <160 °C >24 30 - 60 160-350 °C 64 38 - 68 <5 (depends on catalyst >350 °C properties and process <2 conditions) 25 (winter diesel fuel Isoparaffins <5 production is possible) Aromatics (weight %) 0 0 Oxygenates (weight %) 7 0 CAPEX (USD per 1 tone of
annual capacity) Large scale facility (34 000 600–900 400–500 bbl/d) Small scale facility (300 Not considered 1 400-1 600 bbl/d) economically feasible Catalyst reload cost (large 120 30 scale, m USD/year)
Nowadays, major amount of synfuel production is generated on large scale GTL plants and using natural gas as a feed source. However, increasing demand in APG utilization technologies creates perfect conditions to developing compact GTL plants, which can be implemented to produce diesel fuel, synthetic liquid hydrocarbons, electricity and heat, using available local sources (APG) on site. Nowadays such small scale facilities just start to appear on the market. Hence, they require careful evaluation in terms of their economical and technological viability. For this evaluation GTL technology effectiveness should be estimated for different APG quality and annual production. Also, comparison of GTL method with other APG utilization, fuel supply, and electricity generation solutions need to be done. The possibility of conducting this research can be done by analyzing new INFRA.xtl GTL process. Developed technology is unique, adopted for severe 30 Russian climate conditions, and flexible to use APG of different composition. Analysis of implementing this technology with comparison to alternative APG utilization solutions are in detailed provided in Chapter 3.
2.2 Autonomous power station on the microturbines basis
One of the most popular and modern ways to generate power on oil fields, using APG is microturbines installation. The leader of the microturbines market is Capstone, which controls 95% of the microturbine market [41]. The use of autonomous power generation is especially relevant for small oil fields situated in remote underpopulated areas. Technical characteristics of the Capstone microturbines The producer defines its production as high quality turbines, which can be exploited in diverse power range conditions and herewith fulfill all safety and reliability requirements. The major problem of using traditional power gas turbines for utilization of associated gas is low efficiency at part load and strict requirements to fuel composition. Capstone microturbines in this respect have several advantages. Coefficient of performance is up to 35% even at part load. Power station can use fuel of diverse composition and quality. Exhaust temperatures are not very high, what influences low nitrogen oxides emissions. Among other advantages is simplicity and compactness of the plant. All major parts of the installation are situated in one compact case. Hence, it makes transportation, installation and exploitation processes very easy. Flue gases are utilized efficiently, what allows to produce additional amount of heat apart from electricity generation. High degree of automation allows proper functioning of the plant without permanent personnel presence [42]. Capstone microturbines have been already widely used in Russia, and at the moment it is one of the most effective alternative to APG flaring.
31
Major Capstone advantages are [42]: Consumption of the wide range of fuel, including fuel with unstable composition and hydrogen sulfide content up to 7%. Simple construction, absence of rubbing details. This ensure high reliability, fast and low-cost commissioning and installation, simplicity in connection to the networks. Average plant construction period is 9-15 month. Possibility to conduct maintenance service and repairing in one day on site. Also, construction allows to connect additional power units to the plant that is already in operation. Low noise (less than 60 dB) and vibration level. Periodic maintenance service period of 8000 hours, not more than once per year. Flexibility and high performance characteristics even at part load. Life expectancy between overhauls is 60 000 hours. High efficiency in cogeneration and trigeneration regime. High cost efficiency. Average payback period is 2–4 years, and power generation average cost is up to two times less than power network price. Energy efficiency and resource saving Low operation costs. No need in lubricants, coolant, and engine oil due to the use of air bearings. High degree of automation allows proper remote control of the plant functioning (via GSM module) without permanent personnel presence. Also, working regimes can be programmed in advance. Wide power variation of the plant from 15 kW to 20 МWt. Equipment is supplied in blocks of needed power. Currently Capstone produces 7 basic models with power output 15, 30, 65, 200, 600, 800, and 1000 kW [42]. Major technical parameters of Capstone microturbines basic models are presented in a Table 2.2 below.
32 Therefore the use of APG as a fuel for microturbines is another efficient method of associated gas utilization apart from the GTL technology, which has been described earlier. The comparison of these two methods for conditional oil field is done in the next chapter.
33 Table 2.2 – Technical parameters of Capstone microturbines basic models [42] Parameters С 15 С 30 С 65 С 200 С 600 С 800 С 1000
Power 15 30 65 200 600 800 1000 generation, kW
COP, % 23 (±2) 26 (±2) 29 (±2) 33 (±2) 33 (±2) 33 (±2) 33 (±2)
Voltage, V 380-480 380-480 380-480 380-480 380-480 380-480 380-480
Current , A 23 58 127 310 930 1240 1550
Current 50 50 50 50 50 50 50 frequency, Hz
Weight, tones 0.58 0.58 1.12 3.18–3.64 8.14–9.53 12.60–14.40 15.88–18.14
Length х Width 1.5 х 0.8 х 1.5 х 0.8 х 2.0 х 0.8 х 3.7 х 1.7 х 9.1 х2.4 9.1 х2.4 х2.9 9.1 х2.4 х2.9 х Height, м 1.9 1.9 2.1 2.5 х2.9
34 Table 2.2 (Cont.)
Exhaust 275 275 309 280 280 280 280 temperature, °С
Heat generation, 48.8 84.7 164.2 394.4 1183.3 1577.8 1972.2 kW
Nitrogen oxides <9 ppm <9 ppm <9 ppm emission (15% <9 ppm NOx <9 ppm NOx <9 ppm NOx <9 ppm NOx NOx NOx NOx O2 content)
Level of noise (at 10 m distance), dB <60 <60 <60 <60 <60 <60 <60
Rotational velocity, thousand RPM 96 96 96 60 60 60 60
Life expectancy between overhauls, 60 60 60 60 60 60 60 thousand hours
35 CHAPTER 3. THE SELECTION OF APG UTILIZATION AND ENERGY SUPPLY METHOD FOR THE “CONDITIONAL” OIL FIELD
Calculation method was introduced for choosing energy supply and APG utilization method for conditional oil field because of absence of information on real oil field exploitation parameters. The conditional oil field parameters are as follows: Life cycle (period of operation): 21 years. Recoverable reserves: 4347 thousand tones (small-scale oil field [29]). During the all exploration period oil recovery is conducted by artificial lift. Water is pumped to the field in order to support reservoir pressure Oil is passing treatment on site, what includes removing mechanical impurities, dehydration, and desalting. 3 Oil density at reservoir conditions is ρoil = 805 kg/m , and after degassing 3 gas-free oil density is ρd.oil = 870 kg/m . Let us take associated gas density value at 0 3 20 C и and 760 mmHg equal to ρAPG = 1.125 kg/m For better estimation of gas/oil ratio influence on profitability of using different energy supply and APG utilization methods calculation is conducted for two schemes: first scheme: gas/oil ratio G = 50.0 m3/m3; second scheme: gas/oil ratio G = 100.0 m3/m3.
The most important parameter is APG annual production volume , Mm3, which can be calculated, using following equation:
, (3.1)
where – annual oil production, Kt; G – GOR, m3/m3; 3 ρoil – oil density at reservoir conditions, kg/ m ; 36 i – year of exploitation. Oil field exploration parameters are introduced in the Table 3.2 below. Let us consider three autonomous power generation methods (Table 3.1). It should be noted, that energy supply method from centralized power network is not considered due to significant remoteness of the oil field from the closest cities and power supply units. Moreover, such electricity supply method does not imply APG utilization on site technologies implementation for power generation, what in turn causes problem of APG efficient use.
Table 3.1 – APG utilization and power supply methods for the “Conditional” oil field
Exploitation APG utilization Autonomous power supply method
Diesel Generator; 1 Flaring Fuel is purchased and supplied to the field Synthetic oil production for further use on the Diesel generator; field as a fuel and 2 Electricity is produced partly on the mixing remaining with field by INFRA GTL plant produced oil and sending from the field Power unit on microturbine basis; back- As a fuel for 3 up diesel generator microturbines
37 Table 3.2 – Major “Conditional” oil field exploration parameters
Indicators Mass Associated Associated Number of Flood water Year of fraction of Number of Oil Fluid gas gas water- volume, operation i water in production production production production production injection , 3 3 produced wells 3 , Kt , Kt , Mm , , Mm , wells Tm fluid Np i (scheme 1) (scheme 2) Nw i ki 1 1.8 1.8 0.112 0.224 0 1 0 0 2 3.9 3.9 0.242 0.484 0 1 0 0 3 8.2 8.2 0.509 1.019 0 7 0 0 4 23.8 24.1 1.478 2.957 0.013 12 0 4.8 5 96.7 98.5 6.006 12.012 0.018 12 1 41.2 6 143.5 149.2 8.913 17.826 0.038 25 3 86.0 7 266.7 291.1 16.565 33.130 0.084 46 7 220.9 8 351.3 394.7 21.820 43.640 0.110 70 13 379.2 9 412.2 479.3 25.602 51.205 0.140 86 22 567.2 10 417.7 517.6 25.944 51.888 0.193 101 30 698.4 11 412.7 531.2 25.634 51.267 0.223 93 38 763.0 38
Table 3.2 (Cont.)
12 353.7 466.1 21.969 43.938 0.241 88 43 668.8 13 305.8 430.7 18.994 37.988 0.290 87 43 609.3 14 272.4 414.0 16.919 33.839 0.342 87 43 578.7 15 244.6 400.4 15.193 30.385 0.389 86 43 553.6 16 221.3 392.4 13.745 27.491 0.436 86 43 536.6 17 199.1 385.1 12.366 24.733 0.483 84 43 520.7 18 176.4 377.8 10.957 21.913 0.533 84 42 504.8 19 160.3 372.9 9.957 19.913 0.570 83 42 493.7 20 143.4 365.7 8.907 17.814 0.608 82 41 479.7 21 129.9 360.8 8.068 16.137 0.640 82 41 469.5
39 3.1 Technical assessment of different operating methods of the “Conditional” oil field with 50 m3/m3 gas/oil ratio
Let us compare different operating methods of the “Conditional” oil field with 50 m3/m3 gas-to-oil ratio.
3.1.1 APG flaring. Energy supply is from diesel generator.
In order to conduct correct technical and economical estimation of this method application, it is essential to calculate diesel fuel consumption, which is the major energy source. Main oil field facilities - power users: oil production wells, drill rigs, oil degassing unit, oil processing system, booster pump station, oilfield pipeline, crude oil and diesel fuel tank farm, pumping equipment of the tank farm, pumping equipment of the water supply and water-injection wells, fire protection equipment, utility needs. Energy consumption calculation results are presented on the Figure 3.1. Power consumption peak is observed during 10th year of the lifecycle and equal to 5400 kW . Moreover, emission amount when the first exploitation method is applied (APG flaring, and energy supply is from diesel generator) must be estimated. Emissions in this case can be divided into two groups: from diesel power plant and from APG flaring. Negative impact of APG flaring is tough to estimate. Apart from greenhouse gas emissions flare facility emits huge amount of harmful components, which poison air, soil, water in nearby areas. Such substances include sulphur and nitrogen oxides, carbon monoxide, soot, benzyl, phosgene, toluene, heavy metals (mercury, arsenic, chrome), sulphuric anhydrite, and others.
40 Annual average power consumption, kWt 6000
5000
4000
3000
2000
1000
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 year of exploitation
Figure 3.1 – Average annual power consumption of the “Conditional” oil field
Moreover, thermal pollution in the neighbourhood is significant which impacts can be felt on the distance of several kilometers away from the flare facility and influence changes in meteorological conditions of a whole region [44, p. 45]. Assume that during associated gas flaring the share of vented (“unburned”) gas is amounted to 10% from the total APG volume sent to the flare facility. When
APG (the main component of which is methane) is flared, about 1.8 tones of CO2 emissions are generated for 1000 m3 of APG. Estimated volume of nitrogen and sulphur oxides annual emissions for the considered oil field are 10 and 7 tones respectively [44]. Greenhouse effect from the emissions of CO2 and methane for the first exploitation method is presented in the Table 3.5. It should be noted, that greenhouse effect from vented APG of 10% (methane leaks) is equal to the effect from totally flared remaining 90% of gas.
41 Diesel power plant operation emits approximately 0.5 tones of CO2 equivalent per 1 MWh of electricity production [45]. The selection of the type and amount of diesel generators with unit capacity of 1500 kW has been conducted on the basis of power consumption data of the field. Technical specifications are presented in the Table 3.3.
Table 3.3 – Major technical specifications of the diesel power plant Wilson P1875E1 [43] Manufacturer Wilson (United Kingdom) Model P1875E1 Output Ratings
Standby rating 1875 kVA / 1500 kW Prime rating 1705 kVА / 1364 kW Baseload capacity 1364 kVА / 1091 kW Current at standby rating, А 2700 Current at prime rating, А 2460 Voltage, V 230/400 Frequency 50 Hz Performance data
Engine volume, L 45.8 Specific fuel consumption (prime), 0.257 L/kWh Fuel consumption at 100% load, L/h 350.3 (prime) Fuel consumption at 75% load, L/h 262.8 (prime) Fuel consumption at 50% load, L/h 175.3 (prime) Engine COP, % 40.4
42 Where standby ratings are applicable for supplying continuous electrical power at variable load in the event of a utility power failure. No overload is permitted on these values. Prime ratings are applicable for supplying continuous electrical power at variable load. There is no limitation to the annual hours of operation and this model can supply 10% overload power for 1 hour in 12 hours. Baseload capacity accounts for constant power that generator can supply during a year [43]. Number of generators: 9, including backup generators. Here it should be noted, that this number of generators can cover energy needs of the oil field during the peak energy consumption period (10th year of operation). During the first several years it is enough to install two or three generators and later according to the consumption of energy additional power generation equipment can be installed.
Specific fuel consumption : 0.246 L/kWh [43]. According to these data annual fuel consumption can be estimated. Assume that diesel power plant operates whole year, 8760 hours. Hence, annual electricity output according to needed consumption is equal to average power multiplied by working hours.
Diesel fuel consumption Vd1 i is equal to ratio of annual electricity production to diesel fuel consumption per unit of energy output (specific fuel consumption). Calculation results are outlined in the Table 3.4 below.
Table 3.4 – Diesel fuel consumption for the first exploitation method of the “Conditional” oil field with gas/oil ratio 50 m3/m3 Indicators Year of Power Annual electricity Annual diesel fuel exploi- consumption consumption E , consumption Vd1 i, tation i P , cons i cons i MWh kL kW 1 200 1 752 463.3
43
Table 3.4 (Cont.) 2 200 1 752 463.3 3 450 3 942 1 042.4 4 550 4 818 1 274.1 5 550 4 818 1 274.1 6 2 000 17 520 4 633.1 7 3 375 29 565 7 818.3 8 4 525 39 639 10 482.3 9 4 950 43 362 11 466.8 10 5 400 47 304 12 509.3 11 4 000 35 040 9 266.1 12 3 700 32 412 8 571.2 13 3 550 31 098 8 223.7 14 3 500 30 660 8 107.9 15 3 450 30 222 7 992.0 16 3 400 29 784 7 876.2 17 3 325 29 127 7 702.5 18 3 300 28 908 7 644.6 19 3 250 28 470 7 528.7 20 3 200 28 032 7 412.9 21 3 200 28 032 7 412.9
44 Table 3.5 – Greenhouse gas emissions estimation for the first exploitation method of the “Conditional” oil field with gas/oil ratio 50 m3/m3 Indicators
Emissions Year of Emissions from flaring, t from diesel Total, t exploitation i power plant, t CO CO CO2 CO CH 2 2 2 4 equivalent equivalent equivalent
1 181.1 7.3 335.1 876.0 1 211.1
2 392.4 15.9 726.1 876.0 1 602.1 3 825.1 33.4 1 526.7 1 971.0 3 497.7 4 2 394.8 97.0 4 431.2 2 409.0 6 840.2 5 9 730.1 394.0 18 004.2 2 409.0 20 413.2 6 14 439.1 584.7 26 717.7 8 760.0 35 477.7 7 26 835.7 1 086.7 49 655.9 14 782.5 64 438.4 8 35 348.2 1 431.4 65 407.3 19 819.5 85 226.8 9 41 476.0 1 679.5 76 746.0 21 681.0 98 427.0 10 42 029.4 1 701.9 77 770.0 23 652.0 101 422.0 11 41 526.3 1 681.6 76 839.1 17 520.0 94 359.1 12 35 589.7 1 441.2 65 854.1 16 206.0 82 060.1 13 30 769.9 1 246.0 56 935.8 15 549.0 72 484.8 14 27 409.2 1 109.9 50 717.2 15 330.0 66 047.2 15 24 611.9 996.6 45 541.2 15 111.0 60 652.2 16 22 267.5 901.7 41 203.0 14 892.0 56 095.0 17 20 033.7 811.2 37 069.7 14 563.5 51 633.2 18 17 749.6 718.7 32 843.3 14 454.0 47 297.3 19 16 129.6 653.1 29 845.7 14 235.0 44 080.7 20 14 429.1 584.3 26 699.1 14 016.0 40 715.1
45 Table 3.5 (Cont.)
21 13 070.7 529.3 24 185.6 14 016.0 38 201.6 Total 437 239.0 17 705.5 809 054.1 263 128.5 1 072 182.6
3.1.2 APG utilization for synthetic oil production and electricity generation to cover oil field energy needs
The aim of calculation of the second method is to estimate amount of synthetic oil production from APG and power output by the GTL plant and comparison of this value with needed amount of energy. Synfuel density assume at 800 kg/m3 at 20 0C and 760 mmHg. Also assume that all APG is utilized in the GTL plant. Plant operates 8520 hours a year. Neglect emissions from APG flaring while technical maintenance of the plant is performed, which takes 10 days period [Error! Reference source not found.40]. Hence:
∙ 1000, (3.2)
3 where – annual synthetic oil production, m ; 3 3 – synfuel production per 1000 m utilized APG, kg/1000 m ; 3 – synfuel density, kg/m ; 1000 – transferring coefficient, 1/1000. Synfuel production per 1000 m3 utilized APG is 500 liters. Calculate electricity production by GTL plant for external use, MWh:
, (3.3)
where
46 – annual electricity production by the plant for external use, MWh; p – power generation per 1 Mm3 utilized APG annually, kW/Mm3;
tp – operating hours per year; 1000 – transferring coefficient, kW/МW. Thuswise the difference between energy consumption and energy provided by the plant is , MWh:
= E cons i – E p i , (3.4) where
E cons i – annual electricity consumption of the field, MWh (Table 3.4). If we compare the power output from the plant and power consumption, the following conclusion could be done. Electricity production by the plant doesn't cover oil field needs in energy almost at all exploration stages. (reffer to Table 3.6 and Picture 3.2). That means, diesel fuel should be purchased in order to cover energy shortages. There is an another possible solution when synthetic oil is used for diesel fuel production. In that case, more than half of the synfuel production is used for diesel fuel generation, and that can be not very expedient.
Calculation of the annual diesel fuel consumption V d 2 i , kL, is performed using the formula:
, (3.5) where
- the difference between electricity consumption and electricity provided by the plant in MWh, where only positive values need to be taken into account, i.e when energy shortages occur;
– specific fuel consumption of the diesel station, L/kWh. Assume that GTL plant produces 400 kg of synthetic oil per 1000 m3 processed APG (Table 2.1), hence, for associated gas density of 700 kg/1000 m3
47 average APG consumption for own plant needs is 300 kg (40% out of 1000 m3), what corresponds with 540 kg of CO2 emissions approximately.
Even though plant emits significant amount of CO2 emissions in order to supply heat to the steam reforming reaction, and CO2 emissions from diesel plant also present when plant doesn't cover oil field power needs still total greenhouse gas emission reduction compared to previous method of exploitation is considerable: 3 times less compared to flaring (Table 3.7). It is important to point, that this method features the least greenhouse gas emission value among the all analyzed exploitation methods of the oil field. Hence, GTL plant not only covers oil field energy needs and produces synfuel, but also has minimal effect on ecosystem compared to other exploitation methods.
48 Table 3.6 – Technical analysis of the second exploitation method of the “Conditional” oil field with gas/oil ratio 50 m3/m3 Indicators The difference Year of Associated between electricity Electricity production by Annual diesel exploitati gas Synthetic oil production, consumption and GTL plant for external use fuel consumption on i production 3 Vsf i , m electricity provided Vd2 i , kL 3 , MWh , Mm by the plant , MWh 1 0.11 55.9 95.3 1 656.7 438.1 2 0.24 121.1 212.2 1 539.8 407.2 3 0.51 254.7 446.2 3 495.8 924.5 4 1.48 739.1 1 295.0 3 523.0 931.6 5 6.01 3 003.1 5 261.4 -443.4 0.0 6 8.91 4 456.5 7 807.8 9 712.2 2568.3 7 16.57 8 282.6 14 511.1 15 053.9 3980.9 8 21.82 10 909.9 19 114.2 20 524.8 5427.7 9 25.60 12 801.2 22 427.8 20 934.2 5535.9 10 25.94 12 972.0 22 727.0 24 577.0 6499.2 11 25.63 12 816.8 22 455.0 12 585.0 3328.0 12 21.97 10 984.5 19 244.8 13 167.2 3482.0
49 Table 3.6 (Cont.)
13 18.99 9 496.9 16 638.6 14 459.4 3 823.7 14 16.92 8 459.6 14 821.3 15 838.7 4 188.5 15 15.19 7 596.3 13 308.7 16 913.3 4 472.6 16 13.75 6 872.7 12 040.9 17 743.1 4 692.1 17 12.37 6 183.2 10 833.0 18 294.0 4 837.7 18 10.96 5 478.3 9 597.9 19 310.1 5 106.4 19 9.96 4 978.3 8 721.9 19 748.1 5 222.3 20 8.91 4 453.4 7 802.4 20 229.6 5 349.6 21 8.07 4 034.2 7 067.9 20 964.1 5 543.9
50 Table 3.7 – Greenhouse gas emissions estimation for the second exploitation method of the “Conditional” oil field with gas/oil ratio 50 m3/m3 Indicators Year of exploitation i Emissions from diesel Emissions from INFRA Total, t power plant, t CO2 GTL plant, t CO2 1 828.4 60.4 888.7
2 769.9 130.8 900.7 3 1 747.9 275.0 2 023.0 4 1 761.5 798.3 2 559.8 5 0.0 3 243.4 3 243.4 6 4 856.1 4 813.0 9 669.1 7 7 526.9 8 945.2 16 472.2 8 10 262.4 11 782.7 22 045.1 9 10 467.1 13 825.3 24 292.5 10 12 288.5 14 009.8 26 298.3 11 6 292.5 13 842.1 20 134.6 12 6 583.6 11 863.2 18 446.8 13 7 229.7 10 256.6 17 486.4 14 7 919.4 9 136.4 17 055.8 15 8 456.7 8 204.0 16 660.6 16 8 871.5 7 422.5 16 294.0 17 9 147.0 6 677.9 15 824.9 18 9 655.0 5 916.5 15 571.6 19 9 874.0 5 376.5 15 250.6 20 10 114.8 4 809.7 14 924.5 21 10 482.1 4 356.9 14 839.0 Total 145 135.1 145 746.3 290 881.4
51 3.1.3 APG utilization on microturbines for electricity generation to cover oil field energy needs
Consider module Capstone power plant with 1000 kW unit capacity and 33% COP (Refer to Table 2.2). Assume that all amount of APG is utilized on microturbines. Assume APG lower heating value 9.86 kWh/m3. Hence, the electricity produced by the plant per 1 m3 of APG consumed is equal to 3.25 kWh. Energy generation data are presented in Table 3.8 below.
Calculate annual amount of diesel fuel supply in kL to cover energy shortages in case turbine power generation is less than needed amount.
, (3.6)
where = Econs i – Ep i , the difference between electricity consumption and electricity provided by the plant in MWh, where only positive values need to be taken into account, i.e when energy shortages occur.
Table 3.8 – Technical analysis of the third exploitation method of the “Conditional” oil field with gas/oil ratio 50 m3/m3 Indicators Year Annual of Associated Electricity The difference between diesel fuel exploi gas production by electricity consumption and consumpti tation production power plant , electricity provided by the on i , Mm3 MWh plant , MWh Vd3 i , kL
1 0.11 363.8 1 388.2 367.1 2 0.24 788.2 963.8 254.9 3 0.51 1 657.2 2 284.8 604.2 4 1.48 4 810.0 8.0 2.1 5 6.01 19 543.0 -14 725.0 0.0
52 Table 3.8 (Cont.)
6 8.91 29 001.3 -11 481.3 0.0 7 16.57 53 899.9 -24 334.9 0.0 8 21.82 70 997.5 -31 358.5 0.0 9 25.60 83 305.4 -39 943.4 0.0 10 25.94 84 416.9 -37 112.9 0.0 11 25.63 83 406.4 -48 366.4 0.0 12 21.97 71 482.6 -39 070.6 0.0 13 18.99 61 802.0 -30 704.0 0.0 14 16.92 55 051.9 -24 391.9 0.0 15 15.19 49 433.5 -19 211.5 0.0 16 13.75 44 724.6 -14 940.6 0.0 17 12.37 40 238.0 -11 111.0 0.0 18 10.96 35 650.3 -6 742.3 0.0
19 9.96 32 396.5 -3 926.5 0.0 20 8.91 28 981.1 -949.1 0.0 21 8.07 26 252.7 1 779.3 470.5
As you can see from Figure 3.2, power production on microturbines covers oil field energy needs almost at all exploitation stages compared to previous method when significant amount of energy is generated by diesel station. Carbon emissions for this method are approximately twice less (see Table 3.9) compared to flaring solution (the first method) as all APG amount is utilized on high-efficient turbines with minimal share of unburned gas. It is important to note, that for oil fields with higher gas/oil ratio the second method has significant benefit compared to power generation on turbines. For high volume of APG processed energy production by the plant rises as well.
53 90000
80000
70000
60000 Annual electricity consumption, MWh 50000
40000 Electricity generation by GTL installation, MWh
30000
Electricity generation on 20000 turbines, MWh
10000
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 year of exploitation
Figure 3.2 – The comparison of different exploitation and energy supply methods for “Conditional” oil field with gas/oil ratio 50 m3/m3
Table 3.9 – Greenhouse gas emissions estimation for the second exploitation method of the “Conditional” oil field with gas/oil ratio 50 m3/m3 Indicators Year of exploitation Greenhouse gas emissions from power turbines
1 181.9
2 394.1
3 828.6
4 2 405.0
5 9 771.5
6 14 500.6
7 26 950.0
54
Table 3.9 (Cont.)
8 35 498.8
9 41 652.7
10 42 208.5 11 41 703.2
12 35 741.3
13 30 901.0 14 27 525.9
15 24 716.8
16 22 362.3
17 20 119.0
18 17 825.2
19 16 198.3
20 14 490.5
21 13 126.4
Total 439 101.3
Apart from it, considerable amount of synfuel is produced, which can be used later for diesel fuel production for oil field own needs or sent with recovered ol to the pipeline. Also, the second method gives, apart from economical profit, the best environmental benefit as well compared to other methods.
3.2 Technical assessment of different operating methods of the “Conditional” oil field with 100 m3/m3 gas/oil ratio.
Conduct a similar calculation for the oil field with GOR 100 m3/m3.
55 Assume that energy consumption of the field doesn't change with GOR variation. As gas-to-oil ratio doesn't affect first exploitation method of the oil field (APG flaring, energy supply from diesel generator), the calculation have been conducted only for the second and the third exploitation methods. Carbon emissions for the first exploitation method are presented in the Table 3.10.
Table 3.10 – Greenhouse gas emissions estimation for the first exploitation method of the “Conditional” oil field with gas/oil ratio 100 m3/m3 Indicators Emissions Year of from diesel Emissions from flaring, t Total, t exploitation power i plant, t CO CO CO2 CO CH 2 2 2 4 equivalent equivalent equivalent
1 362.2 14.7 670.3 876.0 1 546.3
2 784.8 31.8 1 452.3 876.0 2 328.3 3 1 650.2 66.8 3 053.5 1 971.0 5 024.5 4 4 789.6 193.9 8 862.5 2 409.0 11 271.5 5 19 460.1 788.0 36 008.4 2 409.0 38 417.4 6 28 878.3 1 169.4 53 435.5 8 760.0 62 195.5
7 53 671.3 2 173.4 99 311.8 14 782.5 114 094.3 8 70 696.4 2 862.8 130 814.5 19 819.5 150 634.0 9 82 952.0 3 359.0 153 492.0 21 681.0 175 173.0 10 84 058.9 3 403.9 155 540.1 23 652.0 179 192.1 11 83 052.7 3 363.1 153 678.2 17 520.0 171 198.2 12 71 179.4 2 882.3 131 708.2 16 206.0 147 914.2 13 61 539.9 2 492.0 113 871.6 15 549.0 129 420.6 14 54 818.4 2 219.8 101 434.3 15 330.0 116 764.3 56 Table 3.10 (Cont.)
15 49 223.9 1 993.3 91 082.4 15 111.0 106 193.4 16 44 534.9 1 803.4 82 406.1 14 892.0 97 298.1 17 40 067.3 1 622.5 74 139.4 14 563.5 88 702.9 18 35 499.1 1 437.5 65 686.5 14 454.0 80 140.5 19 32 259.1 1 306.3 59 691.3 14 235.0 73 926.3 20 28 858.1 1 168.6 53 398.2 14 016.0 67 414.2 21 26 141.4 1 058.6 48 371.2 14 016.0 62 387.2 Total 874 478.0 35 411.0 1 618 108.2 263 128.5 1 881 236.7
The calculation results of the second exploitation method (APG utilization on GTL plant for synfuel production and power generation) are presented in the Table 3.11 and 3.12. The calculation results of the third exploitation method (APG utilization for power generation on gas turbines) are presented in Table 3.13 and 3.14. The comparison of exploitation and energy supply methods for “Conditional” oil field with gas/oil ratio 100 m3/m3 is shown at Figure 3.3.
57 Table 3.11 – Technical analysis of the second exploitation method of the “Conditional” oil field with gas/oil ratio 100 m3/m3 Indicators Year of Associated The difference between Synthetic oil Electricity production by Annual diesel fuel exploitati gas electricity consumption production, GTL plant for external use consumption on i production 3 and electricity provided Vd2 i , kL 3 Vsf i , m , MWh , Mm by the plant , MWh 1 0.22 111.8 190.5 1 561.5 412.9 2 0.48 242.2 424.4 1 327.6 351.1 3 1.02 509.3 892.3 3 049.7 806.5 4 2.96 1 478.3 2 589.9 2 228.1 589.2 5 12.01 6 006.2 10 522.9 -5 704.9 0.0 6 17.83 8 913.0 15 615.7 1 904.3 503.6 7 33.13 16 565.2 29 022.3 542.7 143.5 8 43.64 21 819.9 38 228.4 1 410.6 373.0 9 51.20 25 602.5 44 855.6 -1 493.6 0.0 10 51.89 25 944.1 45 454.1 1 849.9 489.2 11 51.27 25 633.5 44 910.0 -9 870.0 0.0 12 43.94 21 968.9 38 489.6 -6 077.6 0.0 13 37.99 18 993.8 33 277.1 -2 179.1 0.0
58 Table 3.11 (Cont.)
14 33.84 16 919.3 29 642.5 1 017.5 269.1 15 30.39 15 192.5 26 617.3 3 604.7 953.2 16 27.49 6 872.7 24 081.8 5 702.2 1 507.9 17 24.73 6 183.2 21 666.0 7 461.0 1 973.0 18 21.91 5 478.3 19 195.8 9 712.2 2 568.3 19 19.91 4 978.3 17 443.8 11 026.2 2 915.8 20 17.81 4 453.4 15 604.8 12 427.2 3 286.3 21 16.14 4 034.2 14 135.7 13 896.3 3 674.8
59 Table 3.12 – Greenhouse gas emissions estimation for the second exploitation method of the “Conditional” oil field with gas/oil ratio 100 m3/m3 Indicators Year of exploitation Emissions from diesel Emissions from INFRA Total, t power plant, t CO2 GTL plant, t CO2 1 780.7 120.7 901.5
2 663.8 261.6 925.4 3 1 524.8 550.1 2 074.9 4 1 114.0 1 596.5 2 710.6 5 0.0 6 486.7 6 486.7 6 952.2 9 626.1 10 578.3 7 271.4 17 890.4 18 161.8 8 705.3 23 565.5 24 270.8 9 0.0 27 650.7 27 650.7 10 925.0 28 019.6 28 944.6 11 0.0 27 684.2 27 684.2 12 0.0 23 726.5 23 726.5 13 0.0 20 513.3 20 513.3 14 508.7 18 272.8 18 781.5 15 1 802.3 16 408.0 18 210.3 16 2 851.1 14 845.0 17 696.0 17 3 730.5 13 355.8 17 086.3 18 4 856.1 11 833.0 16 689.1 19 5 513.1 10 753.0 16 266.1 20 6 213.6 9 619.4 15 833.0 21 6 948.1 8 713.8 15 661.9 Total 39 360.8 291 492.7 330 853.5
60 Table 3.13 – Technical analysis of the third exploitation method of the “Conditional” oil field with gas/oil ratio 100 m3/m3 Indicators The difference Year of Associated Electricity between electricity Annual diesel exploitat gas production by consumption and fuel ion i consumption production power plant , electricity provided 3 Vd3 i , kL , Mm MWh by the plant , MWh 1 0.22 727.6 1 024.4 270.9 2 0.48 1 576.4 175.6 46.4 3 1.02 3 314.4 627.6 166.0 4 2.96 9 619.9 -4 801.9 0.0 5 12.01 39 086.0 -34 268.0 0.0 6 17.83 58 002.5 -40 482.5 0.0 7 33.13 107 799.8 -78 234.8 0.0 8 43.64 141 995.0 -102 356.0 0.0 9 51.20 166 610.7 -123 248.7 0.0 10 51.89 168 833.8 -121 529.8 0.0 11 51.27 166 812.8 -131 772.8 0.0 12 43.94 142 965.1 -110 553.1 0.0 13 37.99 123 604.0 -92 506.0 0.0 14 33.84 110 103.7 -79 443.7 0.0 15 30.39 98 867.0 -68 645.0 0.0 16 27.49 89 449.2 -59 665.2 0.0 17 24.73 80 476.0 -51 349.0 0.0 18 21.91 71 300.7 -42 392.7 0.0 19 9.96 64 793.1 -36 323.1 0.0 20 8.91 57 962.1 -29 930.1 0.0 21 8.07 52 505.4 -24 473.4 0.0
61 Table 3.14 – Greenhouse gas emissions estimation for the second exploitation method of the “Conditional” oil field with gas/oil ratio 100 m3/m3 Year of Indicators exploitation Greenhouse gas emissions from power turbines
1 363.8
2 788.2 3 1 657.2 4 4 810.0 5 19 543.0 6 29 001.3 7 53 899.9 8 70 997.5 9 83 305.4 10 84 416.9 11 83 406.4 12 71 482.6 13 61 802.0 14 55 051.9 15 49 433.5 16 44 724.6 17 40 238.0 18 35 650.3 19 32 396.5 20 28 981.1 21 26 252.7 Total 878 202.6
62 180000
160000
140000
120000 Annual electricity consumption, MWh
100000 Electricity 80000 generation by GTL installation, MWh
60000 Electricity generation on 40000 turbines, MWh
20000
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 year of exploitation Figure 3.3 – The comparison of different exploitation and energy supply methods for “Сonditional» oil field with gas/oil ratio 100 m3/m3
After conducting the comparison of the results for three different power supply schemes it could be concluded that for gas-to-oil ratio value close to 50 m3/m3 second method of APG utilization (GTL plant) don't cover oil fields energy needs almost at all exploitation stages. In this case APG utilization on microturbines gives better effect. Hence, from technical point of view installation of gas power turbines is the best from considered solutions for oil fields with small gas-to-oil ratio. For higher amount of gas-to-oil ratio (for example, 100 m3/m3) the energy production on gas turbines exceed significantly the needs of the oil field in electricity. Such energy excess is hard to utilize. When the GTL plant solution is applied, energy needs of the oil field can be totally covered, moreover, significant amount of synfuel is produced, which can be used later for diesel fuel generation to
63 cover oil field needs and sending the remaining from the oil field by pipeline, mixing it with produced oil. When talking about carbon and other harmful emissions, this value increases in direct proportion to gas/oil ratio. Obviously, for oil fields with high gas/oil ratio ecological side of the APG utilization plays extremely important role. If possible, those methods, which allow to utilize associated gas in most effective way should be prioritized. For example, the use of GTL conversion technology possess the least amount of CO2 emissions compared to other discussed solutions: for the oil field with GOR 50 m3/m3 carbon emission reduction potential compared to flaring amounts to more than 0.7 Mt CO2 equivalent for the whole life cycle (21 years), and for the oil field with GOR 100 m3/m3 this value could be 1.5 Mt approximately (Table 3.15).
Table 3.15 – Greenhouse gas emissions during project life cycle 21 years for different power supply methods and GOR, in t CO2 equivalent Gas/oil ratio Method of 3 3 50 m3/m3 100 m /m exploitation Flaring. Energy supply from diesel generator; 1 072 182.6 1 881 236.7 fuel is purchased and supplied to the field Synthetic oil production from APG for further use on the field as a fuel and
mixing remaining with produced oil and 290 881.4 sending from the field. Energy supply is 330 853.5 from diesel generator and partly by INFRA GTL plant APG is used as a fuel for microturbines. Energy is generated by the power unit on 439 101.3 microturbine basis; back-up diesel 878 202.6 generator.
64 It is important to note, that currently major amount of oil fields in Russia situated in remote areas have GOR value higher than 100 m3/m3, hence, GTL technology application for these oil fields can be very perspective solution. Technical feasibility of this technology has been demonstrated in this chapter. Moreover, this method of APG utilization can be characterized by the least amount of CO2 emissions compared to flaring and gas turbines application. These facts create the proper ground for developing innovations in the field of synfuel generation and new cost-effective small-scale commercialized plants.
65 CHAPTER 4. ECONOMIC VIABILITY ESTIMATION OF IMPLEMENTATION DIFFERENT POWER SUPPLY AND APG UTILIZATION WAYS FOR “CONDITIONAL” OIL FIELD IN DEPENDENCE ON GAS-TO-OIL RATIO
It need to be pointed that not all values of capital and operating costs were taken into account during the calculation of net present value of cash flow (NPV), but only different ones for the given APG utilization and power supply methods. For example, the calculation doesn’t include the cost of diesel generator as we assume that these expenses are similar for all methods. Operation expenses include only fuel costs as non-fuel expenditure evaluation is rather tough, moreover, in case of using combination of different power supply schemes. Assume that non- fuel costs are low in comparison with fuel costs and almost even among the described energy supply methods; hence, these costs are not included in NPV of cash flow.
4.1 Economic viability estimation of implementation different power supply and APG utilization ways for “Conditional” oil field with gas/oil ratio 50 m3/m3
Economic assessment for the first exploitation method implementation includes calculation of flaring fines and fuel spending. Total costs are discounted to the present value. Calculation is performed in rubbles (RUB).
Assume the price of diesel fuel including its delivery on site pf equal to 100 RUB/l, hence, annual fuel expenditures are:
, (4.1)
66 where
Сf i – annual diesel fuel costs, m RUB;
– annual diesel fuel consumption, kL. Assume is the sum of annual diesel fuel consumption for electricity generation for the first exploitation method of the oil field Vd1 i (see Table 3.4) and annual diesel fuel consumption by vehicles, which is 185.5 kL approximately (500 l/day); 1000 – transferring coefficient, million/thousand. The calculation of flare fines have been conducted in accordance with Russian Federation Government decree № 1148 of November 8 2012 “On the calculation of fines for emissions to air formed through flaring or venting of associated petroleum gas” [9]. Fines are calculated as a sum of fines for emission to air formed through flaring within the established limits of 5% from total APG output and above-limits flared gas volume (clause 10). According to clause 10, 14 and 19 of the decree calculation of fines for emission to air formed through flaring within the established limits is performed without additional coefficient to emission fees.
(4.2)
where
Hj – emission to the air fee for j component. Hj is subjected to the Russian Federation Government Decree № 914 of September 13 2016 “On fees for negative impact on environment and additional coefficients” [46]:
HCH4 = 108 RUB/tone
HC1-C5 hydroc. = 108 RUB/tone (excluding methane)
HNO2 = 138.8 RUB/tone
HSO2 = 45.4 RUB/tone
Assume APG consists of CH4 and C1-C5 compounds. Neglect fees for other components due to low values compared to hydrocarbon content.
67 – j Component flared volume within established limits. 3 Assume 1000 m of APG contains 0.8 tone of CH4 and 0.2 tone of C1-C5 hydrocarbons. Fines for air emissions above the limits are calculated in accordance with clause 10 of the Decree № 1148 of November 8 2012:
(4.3)
where
Kpr = 25 in the period 2017-2019;
Kpr = 100 since 2020;
Kot – additional coefficient for objects / oil fields situated on protected territories. Kot = 2. In case object is not situated on protected territory Kot = 1; K = 25.
Mactual i – actual flared volume of component j.
Calculate annual fines for APG flaring Cfines, m RUB:
=
=
=
(4.4)
where 3 – annual associated gas production volume, Mm . That means that since 2020 oil production companies are forced to pay extremely heavy fines for APG ineffective utilization, in particular, 256 thousand rabbles (about 3.5 thousand US dollars) for 1000 m3 flared APG.
Annual operation costs for the first exploitation method are:
68
. (4.5)
For this exploitation method we don't include capital costs in the calculation.
The value of money changes in time. Calculate discounted costs using the following formula:
, (4.6) where – discount rate. Assume E = 10%. Calculation results are presented in the Table 4.1. As it can be seen from the table, fine costs are becoming very significant nowadays and exceed fuel costs by several times. That is unsustainable burden for oil producing companies. Hence, the implementation of different APG effective solutions is extremely vital.
Table 4.1 – Calculation of costs for the first exploitation method of the oil field with gas-to-oil ratio 50 m3/m3 Indicators Discou APG Year of Diesel fuel Diesel fuel nted Flare Discounted produc exploitatio consumptio cost diesel fines flare fines n i tion , m n, , m fuel , , RUB 3 , kL RUB cost m RUB Mm
7.2 1 0.11 648.8 64.9 64.9 7.2 14.1 2 0.24 648.8 64.9 59.0 15.5 27.0 3 0.51 1 227.9 122.8 101.5 32.7 284.9 4 1.48 1 459.6 146.0 109.7 379.2 1 052.3 5 6.01 1 459.6 146.0 99.7 1 540.6 1 419.6 6 8.91 4 818.6 481.9 299.2 2 286.2
69 Table 4.1 (Cont.) 2 398.5 7 16.57 8 003.8 800.4 451.8 4 249.1 2 872.1 8 21.82 10 667.8 1 066.8 547.4 5 596.9 3 063.6 9 25.60 11 652.3 1 165.2 543.6 6 567.2 2 822.3 10 25.94 12 694.8 1 269.5 538.4 6 654.8 2 535.0 11 25.63 9 451.6 945.2 364.4 6 575.1 1 975.1 12 21.97 8 756.7 875.7 306.9 5 635.2 1 552.4 13 18.99 8 409.2 840.9 267.9 4 872.0 1 257.1 14 16.92 8 293.4 829.3 240.2 4 339.9 1 026.2 15 15.19 8 177.5 817.8 215.3 3 897.0 844.0 16 13.75 8 061.7 806.2 193.0 3 525.8 690.3 17 12.37 7 888.0 788.8 171.7 3 172.1 556.0 18 10.96 7 830.1 783.0 154.9 2 810.4 459.3 19 9.96 7 714.2 771.4 138.7 2 553.9 373.6 20 8.91 7 598.4 759.8 124.2 2 284.7 307.6 21 8.07 7 598.4 759.8 112.9 2 069.6 ∑ ∑ =5 105. =25 538.2 4
The calculation of second method includes capital costs of GTL plant, diesel fuel costs, and revenue from synfuel sale. Taking example of INFRA plant, assume capital costs to be 22 million US dollars [33] (1540 million RUB, rate 1 USD = 70 RUB). GTL plant produces liquid hydrocarbons, and it can be adjusted to produce diesel fuel with output 90% from total liquid fraction production. That requires additional equipment installation which cost is 15% of CAPEX. However, that will provide reliable and free of cost fuel supply for the oil field, what is extremely relevant for remote oil fields. Calculate diesel fuel costs using formulae (4.1) and (4.6). Calculation results are presented in the Table 4.2 below. 70 Table 4.2 – Calculation of costs for the second exploitation method of the oil field with gas-to-oil ratio 50 m3/m3 Inducators Diesel Discounted How much of Year of Diesel fuel fuel diesel fuel diesel fuel Diesel fuel exploit consumptio cost cost consumption can to deliver ation i n, , , , m be covered by GTL on site, kL kL m RUB plant, in kL RUB, 1 620.6 50.3 570.3 57.0 57.0
2 589.7 109.0 480.7 48.1 43.7
3 1 107.0 229.2 877.8 87.8 72.5
4 1 114.1 665.2 448.9 44.9 33.7
5 182.5 182.5 0.0 0.0 0.0
6 2 750.8 2 750.8 0.0 0.0 0.0
7 4 163.4 4 163.4 0.0 0.0 0.0
8 5 610.2 5 610.2 0.0 0.0 0.0
9 5 718.4 5 718.4 0.0 0.0 0.0
10 6 681.7 6 681.7 0.0 0.0 0.0
11 3 510.5 3 510.5 0.0 0.0 0.0
12 3 664.5 3 664.5 0.0 0.0 0.0
13 4 006.2 4 006.2 0.0 0.0 0.0
14 4 371.0 4 371.0 0.0 0.0 0.0
15 4 655.1 4 655.1 0.0 0.0 0.0
16 4 874.6 4 874.6 0.0 0.0 0.0
17 5 020.2 5 020.2 0.0 0.0 0.0
18 5 288.9 4 930.4 358.5 35.9 7.1
19 5 404.8 4 480.4 924.3 92.4 16.6
71 Table 4.2 (Cont.) 20 5 532.1 4 008.1 1 524.0 152.4 24.9
21 5 726.4 3 630.7 2 095.6 209.6 31.1
∑ =186.1
Calculate revenue from synful sales , m RUB:
, (4.5)
where
– annual synfuel amount, which is sent from the oil field by the pipeline. is equal to annual synfuel production (see Table 3.6) excluding synfuel consumption to cover own oil feel needs in diesel (see Table 4.2 column 3);
– price of oil, assume it to be 22 RUB/l; 1000 – transferring coefficient, million/thousand. Annual discounted revenue from synthetic oil sales calculate using the formula:
. (4.6)
The calculation results are outlined in the Table 4.3 below.
72 Table 4.3 – Calculation of revenue for the second exploitation method of the oil field with gas-to-oil ratio 50 m3/m3 Indicators
Synthetic oil to Discounted Revenue the pipeline revenue Year of Synthetic oil from (excluding own from exploitation i production synthetic oil needs synthetic oil , kL sales , m consumption) sales , m RUB RUB , 1 55.9 5.6 0.1 0.1 2 121.1 12.1 0.3 0.2 3 254.7 25.5 0.6 0.5 4 739.1 73.9 1.6 1.2 5 3 003.1 2 820.6 62.1 42.4 6 4 456.5 1 705.7 37.6 23.3 7 8 282.6 4 119.2 90.7 51.2 8 10 909.9 5 299.8 116.7 59.9 9 12 801.2 7 082.8 156.0 72.8 10 12 972.0 6 290.3 138.6 58.8 11 12 816.8 9 306.2 205.0 79.0 12 10 984.5 7 320.0 161.2 56.5 13 9 496.9 5 490.7 120.9 38.5 14 8 459.6 4 088.7 90.1 26.1 15 7 596.3 2 941.1 64.8 17.1 16 6 872.7 1 998.1 44.0 10.5 17 6 183.2 1 163.0 25.6 5.6 18 5 478.3 547.8 12.1 2.4 19 4 978.3 497.8 11.0 2.0 20 4 453.4 445.3 9.8 1.6
73
Table 4.3 (Cont.) 21 4 034.2 403.4 8.9 1.3 ∑ =551.1
The calculation of the third exploitation method includes the cost of autonomous power generation unit on the basis gas turbines and operating fuel costs in order to cover energy shortages in case APG utilization for power generation doesn't cover oil field energy needs (Table 3.8). Also, costs of vehicle fuel are included in the calculation. Similarly, use the formula (4.1) and (4.6) to calculate diesel fuel costs. The results are presented in the Table 4.4. Specific cost of power generation unit including its delivery on site are assumed to be 2000 USD/kW. Hence, including maximum power output value on 10th year of oil field exploitation, calculate capital costs (Table 4.9).
Table 4.4 – Calculation of costs for the third exploitation method of the oil field with gas-to-oil ratio 50 m3/m3 Indicators
Year of Diesel fuel Discounted Diesel fuel cost exploitation i consumption, , diesel fuel cost , m RUB kL , m RUB 1 549.6 55.0 55.0 2 437.4 43.7 39.8 3 786.7 78.7 65.0 4 184.6 18.5 13.9 5 182.5 18.3 12.5 6 182.5 18.3 11.3 7 182.5 18.3 10.3 8 182.5 18.3 9.4
74 Table 4.4 (Cont.) 9 182.5 18.3 8.5 10 182.5 18.3 7.7 11 182.5 18.3 7.0 12 182.5 18.3 6.4 13 182.5 18.3 5.8 14 182.5 18.3 5.3 15 182.5 18.3 4.8 16 182.5 18.3 4.4 17 182.5 18.3 4.0 18 182.5 18.3 3.6 19 182.5 18.3 3.3 20 182.5 18.3 3.0 21 653.0 65.3 9.7
∑ =88.6
4.2 Economic viability estimation of implementation different power supply and APG utilization ways for “Conditional” oil field with gas/oil ratio 100 m3/m3
Conduct a similar calculation for the “Conditional” oil field with gas/oil ratio 100 m3/m3 (second exploitation scheme). The results for the first exploitation method are presented in the Table 4.5 below. Consider the second exploitation method. Capital costs for GTL plant are 35 m USD (2450 m RUB) + 15% for installing additional diesel generation unit. Operation costs and revenue are presented in tables 4.6 and 4.7. It can be seen that GTL pant covers oil field needs in fuel, moreover, significant amount is sent from the oil field mixed with recovered oil.
75 Table 4.5 – Calculation of costs for the first exploitation method of the oil field with gas-to-oil ratio 50 m3/m3 Indicators
APG Diesel Year of annual Diesel Flare Discounted fuel exploitati- produc fuel cost fines flare fines consumpti Discount on, i tion , m , , m on, ed diesel , RUB , kL RUB, fuel cost m RUB Mm3
14.3 1 0.22 648.8 64.9 64.9 14.3 28.2 2 0.48 648.8 64.9 59.0 31.1 54.0 3 1.02 1227.9 122.8 101.5 65.3 569.8 4 2.96 1459.6 146.0 109.7 758.4 2 104.5 5 12.01 1459.6 146.0 99.7 3 081.3 2 839.2 6 17.83 4818.6 481.9 299.2 4 572.5 4 797.0 7 33.13 8003.8 800.4 451.8 8 498.1 5 744.2 8 43.64 10667.8 1 066.8 547.4 11 193.8 6 127.3 9 51.20 11652.3 1 165.2 543.6 13 134.4 10 51.89 5 644.6 12694.8 1 269.5 538.4 13 309.6 11 51.27 5 070.0 9451.6 945.2 364.4 13 150.3 12 43.94 3 950.2 8756.7 875.7 306.9 11 270.3 13 37.99 3 104.7 8409.2 840.9 267.9 9 744.0 14 33.84 2 514.2 8293.4 829.3 240.2 8 679.8 15 30.39 2 052.4 8177.5 817.8 215.3 7 793.9 16 27.49 1 688.1 8061.7 806.2 193.0 7 051.5 17 24.73 1 380.7 7888.0 788.8 171.7 6 344.1 18 21.91 1 112.0 7830.1 783.0 154.9 5 620.8 19 19.91 918.7 7714.2 771.4 138.7 5 107.8 20 17.81 747.1 7598.4 759.8 124.2 4 569.3
76 Table 4.5 (Cont.) 21 16.14 615.3 7598.4 759.8 112.9 4 139.1 ∑ ∑ =
5 105.4 51 076.4
Table 4.6 – Calculation of costs for the second exploitation method of the oil field with gas-to-oil ratio 50 m3/m3 Inducators Diesel Discounted How much of Year of Diesel fuel diesel fuel Diesel fuel diesel fuel exploitation fuel to cost cost consumption, consumption can i deliver on , , m , kL be covered by site, kL m RUB GTL plant, in kL RUB, 1 595.4 100.6 494.8 49.5 49.5
2 533.6 218.0 315.6 31.6 28.7
3 989.0 458.4 530.6 53.1 43.9
4 771.7 771.7 0.0 0.0 0.0
5 182.5 182.5 0.0 0.0 0.0
6 686.1 686.1 0.0 0.0 0.0
7 326.0 326.0 0.0 0.0 0.0
8 555.5 555.5 0.0 0.0 0.0
9 182.5 182.5 0.0 0.0 0.0
10 671.7 671.7 0.0 0.0 0.0
11 182.5 182.5 0.0 0.0 0.0
12 182.5 182.5 0.0 0.0 0.0
13 182.5 182.5 0.0 0.0 0.0
14 451.6 451.6 0.0 0.0 0.0
15 1 135.7 1 135.7 0.0 0.0 0.0
77 Table 4.6 (Cont.) 16 1 690.4 1 690.4 0.0 0.0 0.0
17 2 155.5 2 155.5 0.0 0.0 0.0
18 2 750.8 2 750.8 0.0 0.0 0.0
19 3 098.3 3 098.3 0.0 0.0 0.0
20 3 468.8 3 468.8 0.0 0.0 0.0
21 3 857.3 3 857.3 0.0 0.0 0.0
∑ =43.9
Table 4.7 – Calculation of revenue for the second exploitation method of the oil field with gas-to-oil ratio 50 m3/m3 Indicators Synthetic oil to Discounted Revenue the pipeline revenue from Year of Synthetic oil from (excluding own synthetic oil exploitation i production synthetic oil needs sales , m , kL sales , m consumption) RUB RUB , 1 111.8 11.2 0.2 0.2 2 242.2 24.2 0.5 0.5 3 509.3 50.9 1.1 0.9 4 1 478.3 706.6 15.6 11.7 5 6 006.2 5 823.7 128.3 87.6 6 8 913.0 8 226.9 181.2 112.5 7 16 565.2 16 239.2 357.7 201.9 8 21 819.9 21 264.4 468.4 240.4 9 25 602.5 25 420.0 560.0 261.2 10 25 944.1 25 272.4 556.7 236.1 11 25 633.5 25 451.0 560.6 216.2
78 Table 4.7 (Cont.) 12 21 968.9 21 786.4 479.9 168.2 13 18 993.8 18 811.3 414.4 132.0 14 16 919.3 16 467.7 362.8 105.1 15 15 192.5 14 056.8 309.6 81.5 16 13 745.3 12 054.9 265.5 63.6 17 12 366.5 10 210.9 224.9 49.0 18 10 956.5 8 205.7 180.8 35.8 19 9 956.5 6 858.2 151.1 27.2 20 8 906.8 5 438.0 119.8 19.6 21 8 068.3 4 211.0 92.8 13.8 ∑ =2064.9
Capital and operation costs for the third exploitation method are calculated similarly to the paragraph 4.1 and presented in Table 4.8.
Table 4.8 – Calculation of costs for the third exploitation method of the oil field with gas-to-oil ratio 50 m3/m3 Indicators
Year of Diesel fuel Discounted Diesel fuel cost exploitation i consumption, , diesel fuel cost , m RUB kL , m RUB 1 453.4 45.3 45.3 2 228.9 22.9 20.8 3 348.5 34.8 28.8 4 182.5 18.3 13.7 5 182.5 18.3 12.5 6 182.5 18.3 11.3 7 182.5 18.3 10.3
79 Table 4.8 (Cont.) 8 182.5 18.3 9.4 9 182.5 18.3 8.5 10 182.5 18.3 7.7 11 182.5 18.3 7.0 12 182.5 18.3 6.4 13 182.5 18.3 5.8 14 182.5 18.3 5.3 15 182.5 18.3 4.8 16 182.5 18.3 4.4 17 182.5 18.3 4.0 18 182.5 18.3 3.6 19 182.5 18.3 3.3 20 182.5 18.3 3.0 21 182.5 18.3 2.7
∑ =45.2
4.3 Discounted cash flow
Capital and operation discounted costs for different exploitation methods of the oil field are presented in the table 4.9 below. These values can give an estimation of economical viability of implementation each of three discussed methods. Russian government have established in a recent years extremely heavy fines for APG flaring. That forces oil companies to seek solutions to utilize APG efficiently. Among the discussed solutions is the use of gas power turbines, and for low gas/oil ratios it shows the best effect. However, for high values of APG production power generation on turbines exceed the needed amount by several
80 times. In that case GTL plant installation gives perfect result: capital costs pay back during the project lifetime due to revenue from synfuel production.
Table 4.9 – Discounted cash flow (21 year project life cycle) Discounted cash flow, million RUB (USD/RUB = 70)
Scheme 1 Scheme 2 3 3 (GOR = 50.0 m3/ m3) (GOR = 100.0 m / m ) Method 1. Flaring. Energy supply from diesel generator; fuel is purchased and supplied to the field - 5 105.4 Operation Fuel cost - 5 105.4 costs Fine cost - 25 538.2 - 51 076.4 Total costs - 30 643.6 - 56 181.8 Method 2. Synthetic oil production from APG for further use on the field as a fuel and mixing remaining with produced oil and sending from the field. Energy supply is from diesel generator and partly by INFRA GTL plant.
Capital costs - 1 771.0 - 2 817.5 Operation costs - 186.1 - 43.9 Total costs - 1 957.1 - 2 861.4 Revenue from + 551.1 + 2 064.6 synthetic oil sales APG is used as a fuel for microturbines. Energy is generated by the power unit on microturbine basis; back-up diesel generator.
Capital costs - 1 349.1 - 2 698.3 Operation costs - 88.6 - 45.2 Total costs - 1437.7 - 2743.5
It worth noting, that conducted calculation is not totally universal. The results of the calculation can differ significantly depending not only from geographic location and fluid properties, but also from exploitation method. For example, proposed calculation model doesn’t include possible changes of GOR in time, the possibility or re-injection of associated gas to the reservoir in order to
81 support extraction pressure and diverse APG production volumes in time. Also, the GTL plant INFRA can be adjusted to specific oil field parameters. The system can change synfuel and electricity output ratio, depending on oil field requirements in electricity [40]. This fact is not included in the calculations as well. It is important to note, that there are several obstructions in APG effective utilization solutions application. The main problems are absence of experience in in using GTL small scale installations on the oil fields in Russia and the fact that the use of power gas turbines, which use APG as a fuel source, have not find diverse application in Russia so far mainly because of lack of durability due to severe operation conditions. Hence, it is difficult to estimate reliability of these systems in unfavorable climate conditions of Russian north. Also, conducted calculations of economical viability depends a lot on USD/RUB, discount ratio, and oil price. Currently, there is almost no experience in exploitation of small scale oil fields in Russia situated on signifiant distance from transmission lines and experience in application autonomous power generation units using avaliable local fuels. Therefore, the estimation of different new systems in APG effective utilization is extremely important for successful development of Russian oil and gas industry, decreasing capital investments for new oil field exploration and increasing energy efficiency of petroleum sector. Current research is aimed on general estimation of different autonomous power supply schemes and new APG technologies application.
82 CONCLUSION AND FUTURE WORK
There are numerous reasons for discussing the issue of effective APG use more accurately. Among them are Russian Federation Government decree № 1148 of November 8 2012 “On the calculation of fines for emissions to air formed through flaring or venting of associated petroleum gas”, which establishes strict limitations on APG flaring amounts and heavy fines for those oil companies who break these limits; the exploration of new oil fields in the north severe Russian conditions with lack of infrastructure and higher gas/oil ratio than in tradition oil recovery regions; developing of new effective autonomous power supply solutions with APG use as a fuel source and APG conversion technologies into high quality synthetic fuel directly on the oil field on small scale installations. This work discusses novel technologies in the field of resourсe saving and autonomous power supply solutions. Different APG effective utilization methods have been described. Calculation model for different power supply and APG utilization ways on remote oil fields has been developed as remote oil fields particularly face the problem of reliable power supply and efficient APG use. Calculation has been performed for the different APG utilization methods: on GTL small scale plant, on microturbines, and comparison of these two effective solutions with gas flaring. Proposed calculation model can be successfully applied for fast evaluation of economical profitability and resource saving potential for remote oil fields, depending on oil field parameters, such as gas-to-oil ratio, energy consumption, and also estimation of greenhouse gas emissions. Current research is based on consultations with leading Russian and foreign scientists in the field of energy efficiency, gas chemistry, energy utilization and APG use, and also work with more than fifty scientific publications, thesis, and books. 1. The comparison of three APG energy supply and APG utilization methods has been performed: the case of flaring and energy supply from diesel
83 generator; implementation of GTL small scale plant for synthetic oil production from APG for further use on the field as a fuel and mixing remaining with produced oil and sending from the field; and the third case of APG utilization on gas turbines. 2. On the basis of results of the conducted calculation the following conclusion has been done: described APG effective utilization ways are economically viable and can be applied on remote small scale oil fields in severe Russian conditions. If the gas factor has low value around 50 m3/m3 INFRA GTL plant generates only about 50% of the total energy consumed by the oil field, for this case gas turbine installation is an effective solution. For the oil field with high gas factor (around 100 m3/m3 and more, which is average value for Russia): electricity produced by the INFRA GTL plant covers almost all oil field energy demand, moreover, significant amount of synthetic fuel is produced, and reduced
CO2 emissions. For high values of gas factors the potential of energy generation on turbines is much higher (up to four times) than needed: such energy excess is very hard to utilize in remote areas. 3. Discussed APG effective utilization solutions also possess significant greenhouse gas and other harmful emission reduction potential. Gas turbines reduce emissions because of preventing gas venting into the atmosphere while APG utilization on GTL plant gives 3 to 6 times carbon emission reduction in comparison with flaring method as significant amount of associated gas is converted to synthetic liquid hydrocarbons. However, there are numerous barriers that slow down the implementing of new efficient APG utilization techniques. Such barriers include lack of experience in installing GTL plants on small-scale oil producing facilities, absence of reliable gas turbine technologies for generation power using APG that can operate in severe Russian condition without breakdown and, finally, high initial investments and risks of non-paying back, and this is again due to the lack of experience. I strongly believe that there are ways to overcome these obstructions, such as government incentives in a form of financial support to cover a part of initial costs, investments
84 in research work in the field of APG utilization solutions and establishing pilot plants for demonstrating commercial and technical feasibility of using high effective APG utilization ways. In my opinion, implementation of high efficient resource saving techniques is just question of time. I hope, in the future we will treat our finite natural resources more carefully, and the term gas flaring will remain only as a relic of the past.
85 BIBLIOGRAPHY
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