Highlights

Abstract

Keywords

1. Introduction

2. Tectono-stratigraphic evolution of the Zagros basin during the Paleozoic

3. Material and methods

4. Results and discussion

4.1. Essential elements of the Paleozoic petroleum system

4.1.1. Source rock

4.1.2. Carrier/reservoir rock

4.1.3. Seal rocks

4.2. Processes of the Paleozoic petroleum system

4.2.1. Hydrocarbon generation from the source rock

4.2.2. Migration of generated hydrocarbon

4.2.3. Trapping style

4.3. Implications for future exploration and production activities within the Paleozoic petroleum system

5. Conclusions

Credit author statement

Declaration of competing interest

Acknowledgments

References

Abstract

The Paleozoic petroleum system of the Fars Platform of Iran is analyzed using 1D petroleum system models of 17 deep wells drilled in the study area. The main aim was to investigate the hitherto undocumented influence of salt tectonics on the essential elements and processes of this petroleum system. For the first time, a better understanding about the geohistory evolution of this prolific petroleum system is provided over the Fars Platform. Modeling results indicate that hydrocarbon generation from the Silurian source rock was associated with salt withdrawal synclines. Salt tectonics further controlled the entrapment styles and the geometric distribution of carrier/reservoir rocks and their overlying evaporitic seals. Our findings provide new insights for identifying the remaining exploration potential in the Paleozoic petroleum system of the Fars Platform and suggest that the role of salt tectonics should be considered in the future basin and petroleum system modeling studies in this area.

1. Introduction

Petroleum system analysis has become a critical part of hydrocarbon exploration portfolio in recent years (Allen and Allen, 2013; Alves et al., 2020; Lawson et al., 2018; Magoon and Dow, 1994). It helps exploration geologists to obtain a holistic understanding about the geohistory evolution of the petroleum systems in space and time and to study the complex interaction of many processes influencing the essential elements and processes of the petroleum systems (e.g., Fraser, 2010; Peters et al., 2017). In this study, a preliminary analysis of the Paleozoic petroleum system is conducted for the first time in the Fars Platform of the Iranian Zagros basin (Fig. 1).

The Fars Platform of the Zagros basin is an extremely prolific hydrocarbon province, with several giant and super-giant gas fields in the Paleozoic series (Bordenave, 2008, 2014; Esrafili-Dizaji and Rahimpour-Bonab, 2019). The Paleozoic petroleum system in the Fars Platform contains significant gas reserves in the Permo-Triassic carbonates (Dalan and Kangan formations) in numerous onshore and offshore fields (Esrafili-Dizaji and Rahimpour-Bonab, 2013, 2019; Ghazban, 2007; Kashfi, 1992) (Fig. 1). Notwithstanding the very old history of oil exploration in this basin (i.e. as early as 1900’s), its various petroleum systems were not systematically studied until recent years. The Paleozoic system of this basin is especially less explored and little is known about its stratigraphy (Ghavidel-syooki, 1997; Ghavidel-syooki, 2003; Insalaco et al., 2006; Spina et al., 2018; Szabo and Kheradpir, 1978) and petroleum geology (Alipour et al., 2021; Bordenave, 2008; Esrafili-Dizaji and Rahimpour-Bonab, 2013, 2019; Motiei, 1993).

The main focus of this paper is to analyze the essential elements (i.e. the source rock, carrier, reservoir, and seal rock) and processes (i.e. hydrocarbon generation, migration, and entrapment) for the Paleozoic petroleum system of the Fars Platform. We highlight that the tectonostratigraphic evolution of this area had a great impact on the spatial and temporal evolution of the Paleozoic petroleum system. Results from this study can provide essential input parameters for basin and petroleum system modeling studies in the future. In addition, a better understanding is obtained about the existing play fair-ways and remaining exploration potential in the Paleozoic petroleum system of the Fars Platform.

Keywords

8.1. IEC International Standard 61511: Functional Safety—Safety Instrumented Systems for the Process Industry Sector (Second Edition was published in 2016)

• 8.1.1. Organizing and Managing the Life Cycle
• 8.1.2. Requirements Involving the Specification
• 8.1.3. Requirements for Design and Development
  • (a). Selection of components and subsystems
  • (b). Architecture (i.e., safe failure fraction)
  • (c). Predict the random hardware failures
  • (d). Software (referred to as “program”)
• 8.1.4. Integration and Test (Part of the Verification Process)
• 8.1.5. Validation (Meaning Overall Acceptance Test and Close Out of Actions)
• 8.1.6. Modifications
• 8.1.7. Installation and Commissioning
• 8.1.8. Operations and Maintenance
• 8.1.9. Conformance Demonstration Template
• 8.1.10. Prior Use

1. 8.2. Institution of Gas Engineers and Managers IGEM/SR/15: Programmable Equipment in Safety-Related Applications—5th Edition 2010
2. 8.3. Guide to the Application of IEC 61511 to Safety Instrumented Systems in the UK Process Industries
3. 8.4. ANSI/ISA-84.00.01 (2004)—Functional Safety, Instrumented Systems for the Process Sector
4. 8.5. Recommended Guidelines for the Application of IEC 61508 and IEC 61511 in the Petroleum Activities on the Norwegian Continental Shelf OLF-070—Rev 2, 2004
5. 8.6. Energy Institute: Guidance on Safety Integrity Level

Abstract

This chapter addresses the contents of the IEC 61511 in detail. Each Part from one to three is briefly covered. Some of the following documents are referred to as “second tier” guidance in relation to IEC 61508. Due to the open ended nature of the statements made, and to ambiguity of interpretation, it cannot be said that conformance with any one of them automatically infers compliance with IEC 61508. However, they cover much the same ground as each other albeit using slightly different terms to describe documents and life-cycle activities. IEC 61511 is intended as the process industry sector implementation of IEC 61508.

8.1 IEC International Standard 61511: Functional Safety Instrumented Systems for the Process Industry Sector (Second Edition was published in 2016)

IEC 61511 is intended as the process industry sector implementation of IEC 61508.

It gives application specific guidance on the use of standard products for the use in “safety instrumented” systems using the proven-in-use justification. The guidance allows the use of field devices to be selected based on proven in use for application up to SIL 3 and for standard off-the-shelf PLCs for applications up to SIL 2.

The first edition was issued at the beginning of 2003. Edition 2 was published during 2016 and this chapter has been updatedtoincludethe main changes from edition 1. Unfortunately part 1 which was published in February 2016 contained many editorial mistakes. Some of these editorial mistakes may lead the reader to misinterpret the technical requirements.

1- Introduction

2- Experimental

3- Results and discussion

4- Conclusion

References

Abstract

Petroleum sulfonates are widely used in chemical flooding in China. The samples are complicated and not all the fractions are effective. To recognize effective fraction with excellent interfacial activity and emulsifying property, a preparative liquid chromatography technology was adopted to perform the fraction separation for petroleum sulfonate. Structural composition, interfacial activity，emulsifying property and flooding efficiency of obtained fractions were also analyzed and discussed. It was shown that petroleum sulfonate can be effectively separated into different fractions with obvious structural differences, among which one fraction with the most excellent interfacial activity and the emulsifying property was recognized. The average molecular weight and molecular weight distribution range of this active fraction were 455.5 and 428–468, respectively, which are both crucial for activities. Alkylbenzene dicyclohexane sulfonates, alkyl indan sulfonates, and alkyl naphthalene sulfonates are major structure types, and alkyl chain length is mainly distributed between 12–15, 15–17 and 15–17 respectively. Besides, this active fraction is universal, and it can produce ultralow interfacial tension (~10−3 mN/m) and good emulsifying property against different crude oils including Xinjiang, Changqing, Liaohe Oilfields, etc. in China. The developed technology herein can be used to track and confirm the characteristics and/or active fraction in petroleum sulfonate accurately.

Introduction

Petroleum is one of the most important resources, and meanwhile, it is one of the scarcest resources in China. It is crucial to exploit underground petroleum as much as possible. However still approximate twothirds of crude oils remain in the reservoir after the primary (pressure flooding) and secondary (water flooding) production (Resen et al., 2005; Wang et al., 2014). As a result, many enhanced oil recovery (EOR) techniques have been developed, especially surfactant flooding (Liu et al., 2007; Khan et al., 2009; Dong et al., 2008; Elraies et al., 2011; Hirasaki et al., 2011; Shahri et al., 2012; Ma et al., 2017; Feng et al., 2018). The key to surfactant flooding is to search suitable surfactants, which can reduce interfacial tension (IFT) to an ultra-low level (<10 2 mN/m, even <10 3 mN/m), and/or enhance emulsifying property between the crude oil and the surfactant solution (Santanna et al., 2009; Zhang et al., 2010; Wang and Dong, 2010; Nguyen et al., 2012; Xie et al., 2012; Zhou et al., 2013; Jeirani et al., 2014; Shang et al., 2015). Among the surfactant flooding, petroleum sulfonate is most widely used in China owing to its good interfacial activity, wettability, foam properties, and salinity tolerance, etc. (Sun et al., 2015).

The decision over asset holding is traditionally premised on the double-edge objective of returns maximization and risk minimization. While the class of assets held by a typical investor depends on his attitude towards risks, an optimal investment portfolio requires a strategic combination of alternative assets (commodities, T-bills, stocks etc). To this end, our paper analyzes the role of crude oil prices in predicting stock returns, in addition to the traditional factors, particularly the returns on risk-free assets (such as, T-bills) as enunciated by the Capital Asset Pricing Model (CAPM). We also consider the possibility of nonlinearities in the nexus between crude oil prices and stock returns of nine major oil and gas companies that are currently listed on the Nigerian Stock Exchange over the period of January 2014 to November 2019. Our results show significant in-sample predictability of stock returns using crude oil prices, thereby affirming our argument that oil price matters in the predictability of stock returns for some listed oil and gas firms in Nigeria. We also offer evidence for the role of asymmetries in the predictability of stock returns for the majority of the listed oil and gas companies in Nigeria. By implication, the increasing exposure of the earnings, vis-a-vis, � the share prices of some major oil and gas companies to negative changes in global oil prices suggests the need for diversification of their scope of operations.

Introduction

The Nigerian economy is largely oil dependent, making it highly sensitive to movements in global crude oil prices. Oil price volatility matters for the investment decisions of prospective investors in Nigeria’s oil and gas sector, most especially. This in turn affects the profitability of firms and hence the values of their shares on the domestic stock market (see, for instance, Gupta, 2016 and Soyemi et al., 2017). In the words of Kayalar et al. (2016), changes in crude oil prices are believed to affect stock markets through the channel of expectations. Meanwhile, Basher and Sadorsky (2006) argued that the impact of falling oil prices on stock market differs from country to country depending on whether the country is an oil exporter or an oil importer. In an oil exporting country, an increase in oil prices improves the trade balance, leading to a higher current account surplus and an improving net foreign asset position. At the same time, a rise in oil prices tends to increase private disposable income in oil exporting countries. This in turn enhances corporate profitability, boosts domestic demand and push up stock prices, thereby causing exchange rate to appreciate. In oil importing countries, the process works broadly in reverse: trade deficits are offset by weaker growth and, overtime, real exchange rate depreciates and stock prices decline (Basher and Sadorsky, 2006). The extent to which stock prices are influenced by world oil price changes is explained by the theory of equity valuation, which defines the stock price as the sum of discounted values of expected future cash flows at different investment horizons (Jouini, 2013). Consequently, oil prices affect stock prices directly by impacting future cash flows or indirectly through an impact on the interest rate used to discount the future cash flows. In the absence of complete substitution effects between the factors of production, rising oil prices, for example, increases the cost of doing business, and for non-oil related companies, it reduces profits. Rising oil prices can also be passed on to consumers in form of higher prices, but this will reduce the demand for final goods and services and depress profits.

1. Introduction

2. Literature review

3. Problem description

4. Model

5. Numerical test

6. Conclusion

Acknowledgements

Appendix A. Supplementary data

Research Data

References

Abstract

Financial risks related to crude oil imports are certainly affected by crude oil price uncertainty. Our question is: How important is it to take also physical risks, such as the crude oil exporters’ political risks and transportation risks into account when controlling financial risks in line with the importer’s risk attitude when planning crude oil imports and transportation at a tactical level? In this paper, two-stage stochastic programming models are proposed to illustrate the problem, and a numerical test is conducted to better understand the effects of physical risks. The mechanism for controlling risk will be forward physical contracts. The results show that the real financial risk is much higher than the importer might believe if physical risks are not considered. Unless the importer is risk neutral, more forward crude oil will be imported when physical risks are considered, and the distribution of forward crude oil will depend strongly on correlations among risks.

Introduction

Crude oil is of strategic importance in all countries, and it is often crucial for a crude oil importer’s national economy. Every import country wants to secure an uninterrupted availability of crude oil at an affordable price. But many crude oil exporters, particularly those located in the Middle East, Africa and Latin America, suffer political instability or have a high risk potential (Vivoda, 2009). The unstable political situations in these regions will create supply disruption risks for importers. There are also correlations between political risks of different exporters in the same region, since they are impacted by some common risk factors (Li et al., 2009). For example, the war in Yemen, with Iran and Saudi Arabia involved, leads to instability in the Middle East. Disruptions in supply will lead to an imbalance between supply and demand in the international crude oil market, and global crude oil prices will fluctuate. Since the global crude oil market is highly integrated, the crude oil prices of other exporters will also be affected. In addition to the political risks and crude oil price fluctuations of exporters, there are also transportation risks. Most crude oil is transported by ship. But the straits and canals in the maritime transportation network are exposed to risks due to political instability in neighboring countries, as well as terrorism, piracy, conflicts and other extreme events (Emmerson and Stevens, 2012). For example, the political instability in the Middle East threatens the safety of the Bab el Mandeb and the Suez Canal. If certain straits or canals are closed, the crude oil transportation will be affected.

Due to the political risks of exporters, transportation risks of straits and canals, and oil price uncertainty, crude oil import and transportation decisions are very challenging for importers, who want to control financial risks. But this problem is underexplored. In previous studies, the focus has mostly been on crude oil price fluctuations, and different hedging strategies are proposed. Chen et al. employed geometric Brownian motion processes to model oil price fluctuations, and determined the optimal oil procurement. Operational and financial hedging strategies are proposed by Ji et al. (2015) to manage risks caused by oil price fluctuation. Chang et al. (2011) used a dynamic multivariate GARCH to obtain a crude oil hedging strategy. Sukcharoen and Leatham (2017) proposed the use of vine copulas to capture characteristics of price changes and estimate multiproduct hedge ratios for a refinery to manage risks. In these studies, there are no considerations of selection of exporters, so the political risks of exporters are not taken into account. In addition, the transportation risks are also not considered.

As a clean fossil fuel with great reserves, natural gas hydrate (NGH) is widely regarded as an important future alternative energy source. NGH is widely distributed in onshore tundra and shallow sedimentary layer s in the deep sea. These sedimentary layers typically exits shallow burial depth, poor diagenesis and low strength characteristics; moreover, the decomposition of NGH can also greatly reduce reservoir strength. Therefore, NGH development can easily cause s many geomechanical problems , including reservoir instability, sand production and seabed landslide s, etc., which may further trigger a series of environmental disasters such as tsunami s, natural gas leakage and the acceleration of global warming. This study mainly reviews the research progress regarding geomechanical issues in NGH development , including mechanical properties of NGH -bearing sediments, borehole stability, hydraulic fracturing, sand production, reservoir settlement and seabed landslide s. In addition to previous research achievements regarding geomechanical problems in NGH exploitation , the limitations and challenges are also discussed , and several questions and insightful suggestions are put forward for future research from our point of view.

Introduction

With rapid economic and social development, the demand for energy has witnessed sustainable growth and the exploitation of conventional fossil fuels encountered a bottleneck; meanwhile, scholars are paying more attention on unconventional energy such as natural gas hydrate (NGH). NGH is a type of ice -like compound formed by the combination of water and gas molecules at low -temperature , high -pressure conditions (Sloan Jr and Koh, 2007). In the natural world, because of large reserves and its high energy density, NGH is regarded as one of the most important alternative energy sources in the 21st century and now attracts widespread attention from the scholars all over the world (Chong et al., 2016; Makogon et al., 2007;Nair et al., 2016). Approximately 1 ,500 billion ton s carbon is stored in NGH, which occupies estimated 25% of mobile organic carbon in global land -ocean -atmosphere system s (Beaudoin et al., 2014) , almost twice that of proven conventional mineral fuels such as coal, oil and natural gas (Kvenvolden, 1998; Yan et al., 2017). Because the massive amount of NGH on the seafloor has been found through deep sea drilling (Huene et al., 1980; Moore et al., 1982), many countries have successively formulated research and development plans of NGH, with the ultimate aim of achieving commercial development of NGH ( Dickens, 2004; China Geological Survey Bureau, 2017; JOGMEC, 2017; Chen et al., 2018; Wu and Wang, 2018).

For heavy reservoirs, conventional oil recovery methods are polymer flooding and Steam-assisted Gravity Drainage (SAGD). Such methods are affected by various factors including reservoir thickness, formation heterogeneity, heat loss, and cost, especially in deep heavy oil reservoirs. In these deep reservoirs, their crude oil has a viscosity in the tens of thousands of centipoises at surface conditions, but only a few hundred centipoises at high temperature. There is sufficient mobility of crude oil making it possible for nitrogen (N2) huff-n-puff to be applied. Since foamy oil is a very significant production mechanism in huff-n-puff process, this study is to confirm the ability of nitrogen to form foamy oil in a deep heavy oil reservoir. This study includes two types of tests. The first category is the PVT tests to measure N2 solubility in heavy oil. It was found that the solubility of nitrogen in the oil sample at 50 °C and 7 MPa is 7.54 m3 /m3 . The second category is the pressure depletion tests conducted in a 1-D cylindrical model to observe the flow behavior. These tests are conducted consistently at four different pressure decline rates. It confirmed the possibility of foamy oil formed by nitrogen and summarized the variation of the flow pattern. This research is a preliminary basic study of N2 huff-n-puff in heavy oil reservoirs. Confirmation of the technology’s feasibility will significantly reduce the cost of exploiting heavy oil reservoir.

Introduction

Petroleum, although a nonrenewable energy source, will remain as the primary source of energy worldwide [23]. Unlike the increasing demand for oil, the scarcity of conventional oil reservoirs makes it a challenge to meet the demand. Fortunately, unconventional oil reservoirs account for 70% of total oil reserves worldwide [10]. Therefore, exploitation of unconventional oil reservoirs in the current oil industry has become the main focus to increase oil production [5,36,46]. Unconventional oil reservoirs are reservoirs with a wide variety of sources, which include oil sands, heavy oil, gas to liquids, tight oil, oil shale, and other liquids [36]. Among them, the recoverable reserves of tight oil and heavy oil are 47.0% and 29.7%, respectively. Tight oil and heavy oil are considered as the momentous resources for meeting the rapidly growing oil demand. Heavy oil generally consists of oil sand, extra heavy oil or bitumen, which are trapped in unconsolidated sandstones. These types of crude oil are extremely viscous, making extraction difficult. Due to the high viscosity, heavy oil and bitumen are unable to be pumped out by conventional production methods. Compared with conventional reservoirs, there is more residual oil in unconventional reservoirs after primary recovery. Nevertheless, due to the unique properties of heavy oil and the unconsolidated sandstones, the conventional displacement method of restoring reservoir pressure utilizing water, natural gas or carbon dioxide injection has no functional effect [19]. Thermal recovery is currently the preferred method to exploit heavy oil reservoirs [40]. Thermal methods mostly refer to steam injection, which is the most effective method to reduce heavy oil viscosity.

We evaluate the impact of changes in the price of crude oil on the United Kingdom (U.K.) real gross domestic product (GDP) growth rate by way of an out-of-sample forecasting analysis. We compare the performance of several nonlinear models and determine, which aspects of nonlinearities are most useful for obtaining forecast improvements. Likewise, our approach takes into account the possibility that relative predictive performance can vary over the out-of-sample period. Results based on quarterly data from 1974q1 through 2018q4 illustrate that our conclusions depend on the definition of forecast improvement and whether we rely on pairwise or multiple forecast comparison. For instance, it is very difficult tofind evidence that point forecasts exploiting crude oil price variables are statistically significant more accurate than point forecasts produced under the benchmark. On the other hand, the null hypothesis of no population-level predictability is borderline rejected for certain nonlinear crude oil price variables. We also observe notable differences between using real-time and ex-post revised GDP data with regards to local out-of-sample performance. The predictive power associated with the more successful crude oil price measures appears to concentrate in the early 1990s and around the onset of the Great Recession.

Introduction

The aim of this study is to evaluate the predictive impact of changes in the price of crude oil on the United Kingdom (U.K.) real gross domestic product (GDP) growth rate via an out-of-sample analysis. We are motivated to do so based on several interesting results reported in widely cited studies, such as Bachmeier, Li, and Liu (2008), Carlton (2010), Kilian and Vigfusson (2013), Ravazzolo and Rothman (2013) and Ravazzolo and Rothman (2016) . 1 The central question running through these studies is whether changes in the price of crude oil have a predictive impact on the real U.S. GDP growth rate out-of-sample.2 However, in the context of other countries relatively less is known about whether (a): Changes in the price of crude oil help forecast the country specific real GDP growth rate, (b): If the predictive impact of crude oil price changes on the real GDP growth rate is nonlinear and (c): If so what types of nonlinearities. In fact, in their seminal study, Kilian and Vigfusson (2013) argue that understanding the nonlinear/asymmetric predictive impact of changes in the price of crude oil on the real GDP growth rate deserves further study on non-U.S. data. Arguably, the U.K. can be considered as an interesting case because it is a developed, open economy, which has transitioned from being a net crude oil importer in the 1970s to a net exporter in the 1980s and early 1990s before returning to being a net importer again since the mid 2000s.3 This in turn, provides a very good opportunity to evaluate (a), (b) and (c). Likewise, studies such as Jim
enez-Rodríguez and S
anchez (2006), Harrison, Ryland, and de Weymarn (2011), Millard (2011) and Millard and Shakir (2013) focus on the causes and effects of crude oil price changes on the U.K. economy via examination of impulse response functions. However, they do not account for nonlinearities in the relationship between the price of crude oil and the growth rate. Similar to simulations provided by the National Institute for Economic and Social Research (NIESR) and the Bank of England they conclude that a fall in the price of crude oil leads to an increase in the U.K. GDP growth rate. To date, a comprehensive analysis on the predictive impact of crude oil price changes on the U.K. GDP real growth rate has not been conducted. The purpose of this study is to fill this gap. Finally, the increasing financialization of the crude oil market and the important role of crude oil in the context of a developed, open economy, such as the U.K. makes our analysis interesting to a broad audience.

1. Introduction

2. Method and data

3. Results and discussion

4. Conclusions

Acknowledge

Appendix A. Supplementary data

References

Abstract

The petroleum refining industry is an important contributor to industrial volatile organic compounds (VOCs) emission. As a foundational work for VOCs control, previous VOCs inventories usually treated the petroleum refining industry as an integrated part resulting the unknown of VOCs emission characteristic among different units. Refined management has becoming an inevitability with the increasing strictness of environment standards. This study aims to develop a holistic method for VOCs emission inventory of the petroleum refining industry toward specificity, accuracy and economization, in which a source categorization was proposed from unit angle, and a systematic estimation method was developed from the material flow point of view. This method provides a more specific and accurate quantification method, especially for fugitive emission sources which is a pivotal but difficult problem in VOCs inventory establishment. Through application to a typical medium-scale refinery located in northern China, a unit-specific VOCs emission inventory with 48 emission sources and respective local VOCs emission factors (EFs) was established. Estimation results and economic cost of the developed method were compared with those of other methods. In this study, the integrated EF was 0.77 kg-VOCs/t-crude oil refined, which was in the same order with most previous studies. Inventory results implied that increasing hydrotreating unit, reducing chemical device and solvent-used unit (e.g., polypropylene production, furfural refining unit), upgrading catalytic reforming unit were beneficial to control VOCs emissions in this study. Using floating-roof tanks rather than fixed-roof tanks is an effective way to reduce VOCs emissions from storage tanks, which decrease 72%–86% of diesel storage emissions. Economic cost analysis showed that the advantage of this method lied in lower labor cost, and no subsequent monitoring cost. Suggestions proposed from this study provide feasible measures for local policy makers to control VOCs emission and determine abatement strategies of the petroleum chemical industry. Meanwhile, this study greatly helps enterprises promote the fine management of VOCs-containing materials from the overall processes to identify VOCs control emphasis.

Introduction

Air pollution characterized by high concentration of groundlevel ozone (O3) and fine particulate matter (PM) has caused increasing concerns in China due to its significant adverse impact on human health (Dai et al., 2017; Rohde and Muller, 2015). Volatile organic compounds (VOCs) are key precursors for the formation of ozone and PM through complicated photochemical and physical reactions (Shao et al., 2009a, 2009b; Yuan et al., 2013). Ozone reduction is largely accomplished by the control of VOCs (Tang et al., 2012). Chinese government has been focusing on VOCs pollution problem. The 13th five-year plan for ecological and environmental protection made the reduction target that the total national VOCs should decreased by more than 10% during the 13th five year. Standard for fugitive emission of volatile organic compounds (MEEC, 2019b) and comprehensive VOCs treatment scheme for key industries (MEEC, 2019a) were successively published to promote VOCs prevention work, recently. The petroleum refining industry is an important contributor to VOCs emissions, accounting for approximately 3% of the total anthropogenic VOCs emissions (Wei * Corresponding author. et al., 2016). In 2015, the petrochemical industry become one of the first batch of pilot industries to implement VOCs Pollution Pilot Charge Method published in China. Thus, a specific VOCs emission inventory of the petroleum refining industry is necessary and foundational for VOCs emissions reduction and equitable control policies.

1- Introduction

2- Experimental

3- Results and discussion

4- Conclusion

References

Abstract

Petroleum coke is the waste from the delay coking process during petroleum refining. It is urgent to solve the problem of the effective and environmental utilization of high-sulfur petroleum coke. Chemical looping gasification (CLG) is employed in the application of petroleum coke for syngas production and sulfur recovery for the first time. The conventional steam gasification was for comparison to have a better understanding of the chemical looping process of petroleum coke. The presence of hematite improved the carbon conversion efficiency to 70.13%, although the fraction of the effective syngas decreased slightly. Experiments are conducted to evaluate the effects of temperature, steam flow rate and the sizes of fuel and hematite on the conversion of carbon and sulfur in a batch fluidized bed. The data shows that the effective syngas accounts for 83.51% and the molar fraction of H2S/SO2 is about 2, when the fuel size was 0.1–0.3 mm, and the hematite size was 0.3–0.4 mm at the steam flow rate of 1 g/min at 900 °C. Moreover, that condition is advantageous to the further utilization of the flue gas stream for sulfur recovery via Claus process. The size of oxygen carrier has a significant influence on distribution of sulfur species releasing. The high-content sulfur in the petroleum coke did not remain on the surface of hematite and the oxygen carriers were not poisoned. As a consequence, chemical looping gasification with hematite as oxygen carrier is an excellent technique for petroleum coke conversion coupled with sulfur recovery.

Introduction

Petroleum coke is the waste from the delayed coking process in the petroleum refining industry with high calorific value and low ash content. It is classified to high and low sulfur petroleum coke depending on the sulfur content. The low sulfur one can be used in many fields such as fuel, anode and electrode. However, the high sulfur petroleum coke faces a great challenge to be utilized because of the pollution [1,2]. Moreover, the production yield of high sulfur coke is overstocked with a high increasing rate, while the low sulfur one is in short supply [3]. Therefore, the utilization of high sulfur petroleum coke in a benign environmental and effective method is being solved urgently [4]. Gasification is considered as a cleaner and economic process to convert solid fuels in comparison with combustion [5e7]. When petroleum coke is used in the gasification technology, the sulfur compounds in the raw gas product would be converted into elemental sulfur in the Claus plant. But the gasification reactivity of petroleum coke is rather low due to its carbon structure and low combustibility [8,9]. Chemical looping gasification (CLG) is a promising gasification technology to produce syngas, sharing the same principle with chemical looping combustion (CLC) [10]. Generally, the system involves two reactors, a fuel reactor and an air reactor, with the oxygen carrier circulating between the two reactors as shown in Fig. 1. The oxygen carrier transfers lattice oxygen and heat to achieve the fuel partial oxidation and gasification in the fuel reactor, while the reductive oxygen carrier is transported for regeneration in the air reactor. Compared with the traditional gasification technology, CLG has several advantages [11,12]. The regeneration of oxygen carrier can supply heat for gasification, thus balancing the heat in the system with less extra energy input.

1. Introduction

2. The U.S. Petroleum refining industry

3. U.S. crude oil production and consumption

4. U.S. exports of finished petroleum products

5. Scenario analysis

6. Results & discussion

7. Conclusion

Acknowledgement

References

Abstract

In 2018 the U.S. petroleum refining industry is the largest and most advanced in the world. Continuous consolidations and investments in complex refinery additions have allowed this industry to remain competitive and the shale oil revolution has contributed to the U.S. becoming a net exporter of refined petroleum products in 2008. In light of current and forecasted changes in refined petroleum product demand and worldwide refining capacity additions, the U.S. petroleum refining industry faces new challenges. This paper provides an in-depth study of this industry, presenting past trends, its current state and the effects that a changing U.S. crude oil production has on refiners. Furthermore, a scenario analysis is used to forecast future production levels and the volumes of major refined products available for exports over the years 2017–2032. The competitiveness of current U.S. gasoline and diesel exports is evaluated and forecasted gasoline and diesel demand in current export markets is compared to available export volumes. Major challenges facing refiners by changing market conditions and new regulatory rules are discussed. Finally, a set of recommendations is provided.

Introduction

The U.S. petroleum refining industry is the largest and most sophisticated of its kind in the world in 2019. Since the lifting of the U.S. Crude Oil Export Ban in December 2015 all international trade restrictions in this industry have been lifted and the U.S. market is fully integrated in the world market for refined products. In 2017 global petroleum refining capacity reached 98.7 million barrels per day (MMBD) and the U.S. accounted for nearly 19% of this (OECD/IEA, 2018). The International Energy Agency forecasts U.S. domestic capacity to further increase by 0.2 MMBD by 2022 (OECD/IEA, 2017a, pp. 1–147). However, with changing regional trends in refined petroleum product demand growth, shifts in refining capacity additions, and the increased complexity of refineries around the world (Zavaleta, Walls, & Rusco, 2015), the U.S. petroleum refining industry faces new challenges. Over the years 2000–2017 global refining capacity has grown by 17 MMBD, and Asia accounted for 65% of these additions, while the Middle East accounted for 15% (Gresh, Royall, & Yu, 2017, pp. 1–106). A similar trend is expected through 2023 as world refining capacity is forecasted to increase by 7.7 MMBD from 2017 levels (OECD/IEA, 2018). The Middle East (with big projects in Kuwait, and Saudi Arabia),1 China, and India account for more than half of all projected capacity additions from 2017 to 2023. The latter investments are driven by strong economic growth leading to an increase in the standard of living and an increased demand for transportation fuels in many non-OECD countries. In addition, new fuel specifications that have come into effect recently in Asia (Lofting, Malek, Arun, & Dsouza, 2018), and China’s desire to become a prominent supplier of refined petroleum products to South East Asian nations has also spurred capacity increases.

1- Introduction

2- Literature review

3- The rise of renewable energy

4- Analysis of the renewable energy strategies of global oil majors

5- Results and discussion

6- Conclusion and further research

References

Abstract

Renewables, especially wind and solar, are taking a role of increasing importance in the energy industry. Therefore, oil majors are progressively positioning themselves for the proclaimed energy transition. This indeed raises the question of whether sizeable capital allocation into renewable energy could indicate that oil majors are indeed transforming into energy companies. This paper helps to address this query by investigating the oil majors’ renewable energy strategies and investments. Furthermore, a complete quantification and categorization of oil majors into renewable leaders or laggards is provided. Results show that of the eight oil majors, five have undertaken considerable investment into renewable energy. The analysis also demonstrates the strong linkage between the oil majors’ proved oil reserves and their renewable energy strategies.

Introduction

According to BP’s 2018 Energy Outlook, renewable energy will be the fastest-growing source of energy, increasing five-fold by 2040 thus providing around 14% of global primary energy at this future point in time [1]. Concurrently, oil majors are gradually facing potential prospects as a declining industry: while peak demand for oil has not yet occurred so far, it may be expected that this scenario is indeed approaching as oil demand growth slows and eventually peaks [2,3]. In light of this, the oil industry is confronted with the question of whether it should try and at least partially reinvent itself as renewables businesses [2] as in fact also the rising cost of hydrocarbon extraction creates an incentive to consider accelerating the energy transition away from hydrocarbons toward progressively more affordable renewable energy resources [4]. In other words, could renewables be the oil majors’ next big business to which scarce capital will be diverted to from upstream oil [5]? As such, oil firms are essentially attempting to figure out how the best presently available cash cow in the world can be replaced [6] for the benefit of their own sustainable future. Furthermore, growing concerns about climate change following the Conference of the Parties 21 (COP21) Paris Agreement [7] may provide an additional drive for such strategy to hedge against hardening investor sentiment towards carbon emissions. Following COP21, more than 170 countries agreed to try limiting global warming to well below two degrees Celsius, an effort that will require major investments in low-carbon energy sources. In witness whereof, the chief executive officer of Royal Dutch Shell Mr. Ben van Beurden, for example, told investors recently that Royal Dutch Shell is no longer an oil and gas company, but an energy transition company [8]. However, the current business models of oil majors and renewable companies are distinctively different, and the oil industry is likely to have, for example, a different cost of capital to the renewables sector [2]. Most renewable ventures, like wind and solar projects, churn out cash flows akin to annuities for several decades after initial up-front capital expenditure generally with low price risk [5], quite different to the business models of oil majors that face oil price risk. However, one could argue that with an increasing share of intermittent renewables, the power business is becoming more akin to the oil industry requiring a trader’s skillset to manage increasing volatility and provides a hedge in a future low carbon environment. Therefore, this paper sets out to analyze the question of whether oil companies are transitioning to become energy companies in the broader sense (Fig. 1) and are making sizeable capital allocations to the renewable energy sector as part of their corporate strategies. Section 2 provides a literature overview. Section 3 presents the rise of renewable energy. Section 4 analyzes the strategic responses of the eight oil majors. Section 5 discusses the results, and Section 6 concludes and provides ideas for further research.