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.

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).

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.

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.

Abstract

We analyze the rate of return (ROR) and risk factors faced by Shell Exploration, an international oil company (IOC), in its Soroosh and Nowrooz buy-back service contract in Iran. In particular, based on our models of cash flow, we analyze the buy-back contract specific risk factors that can contribute to a reduction in the rate of return for the international oil company. Our cash flow models resemble the cash flow of buy-back service contracts before the Iranian government changed the way it determined the capital cost ceiling and pre-defined the oil price in these contracts in 2008–2009. Our actual and contractual cash flow models reveal that Shell Exploration’s actual ROR was much lower than the contractual level. Furthermore, we find that among the risk factors that we considered, a capital cost overrun has the greatest negative effect on the IOC’s ROR. Moreover, we show that there is a potential for modifying the contracts in order for the IOC to face an actual ROR closer to the contractual ROR even if the contract faces cost overrun or delay, without exceeding the maximum contractual ROR that the National Iranian Oil Company is willing to give.

Introduction

In recent years, some oil and natural gas producing countries have shown an increasing interest in adopting variations of service-type contracts rather than production sharing contracts or concessions in their oil and natural gas development and exploration projects (Ghandi and Lin, 2014).1 A service contract2 is a long-term contractual framework that governs the relation between a host government and international oil companies (IOCs) in which the IOCs develop or explore oil or natural gas fields on behalf of the host government in return for pre-determined fees and in which in most cases the host government does not hand over the control of the extracted or subsoil or sub-surface resources to the IOCs (Ghandi and Lin, 2014).3 One type of service contract is Iran’s buy-back service contract.

 مجله مدیریت مالی چند ملیتی – Journal of Multinational Financial Management

1. Introduction

Previous studies show mixed support for the hypothesis that foreign affiliates are the main channel of embodied knowledge flows (Lall, 2001). The share of foreign direct investment (FDI) inflows to the MENA region in global FDI has increased in the past decade (see Table A.1, appendix A). Specifically, 59% of the FDI inflows to MENA countries in 2010 were for four countries: Saudi Arabia (37%), Egypt (8%), Israel (7%), and Qatar (7%). Most FDI to the MENA region does not flow to the manufacturing and information and communications technology (ICT) sectors, which are more relevant to technology diffusion than other sectors are (e.g., natural resources or tourism).1 Barro and Sala-i-Martin (1997) indicate the importance of technology diffusion as a channel of economic growth in developing countries. Fransman (1985) indicates that international technology diffusion uses two different types of transactions. The first is “formal” transactions, which include joint ventures, licensing, and goods trade. The second is “informal” transactions, which include linkages between multinational enterprises (MNEs) and local firms as well as scientific exchange. In both modes, MNEs are the main source of technology diffusion (Lall, 2001).

Blomstrom and Sjoholm (1998) argue that foreign affiliates may affect the productivity of local firms in two aspects. First, MNEs have strong technological and financial capabilities that allow them to compete with local firms. Second, the entry of MNEs encourages local firms to improve their capabilities to become competitive with foreign affiliates. This may force local firms to change their production techniques and their managerial skills. With these two aspects in mind, this study investigates the ability of MENA countries to absorb technology diffusion from foreign affiliates. Specifically, this study contributes to the empirical literature by investigating the impact of FDI on labor productivity (not economic growth)2 in MENA countries. Previous studies have focused on the determinants of FDI and the impact of FDI on economic growth in MENA countries (see Ahmadi & Ghanbarzadeh, 2011, for a review). In addition, this study develops a simple theoretical model to illustrate the link between foreign affiliates, technological catch-up, and host-country labor productivity growth.

The remainder of this study is organized as follows. Section 2 discusses the main theoretical approaches and empirical difficulties in testing the technology diffusion from FDI. Section 3 provides the empirical specifications. Section 4 discusses the data sources. Section 5 indicates the empirical findings. Section 6 offers a conclusion and policy implications.

مقدمه

در مطالعات قبلی شاهد حمایت از فرضییات مطرح شده بودیم که بیانگر این بودند که وابستگان خارجی، کانال اصلی جریان های دانش محسوب می شوند. در دهه گذشته سهم سرمایه گذاری مستقیم خارجی (FDI) در منطقه خاورمیانه و شمال آفریقا یا به اختصار (MENA) در FDI جهانی افزایش یافته است. به طور مشخص، 59 درصد از ورود سرمایه گذاری مستقیم خارجی به کشورهای MENA در سال 2010، چهار کشور، عربستان سعودی (37 درصد)، مصر (8 درصد)، اسرائیل (7 درصد) و قطر (7 درصد) بودند. بیشترین سرمایه گذاری مستقیم خارجی به منطقه خاورمیانه و شمال آفریقا به بخش تولید و فناوری اطلاعات و ارتباطات (ICT) مربوط نمی شود بلکه بیشتر به انتشار فناوری نسبت به بخش های دیگر (به عنوان مثال، منابع طبیعی یا گردشگری) مربوط می شود. بارو و سالا مارتین در سال 1997، اهمیت انتشار تکنولوژی را به عنوان کانال رشد اقتصادی در کشورهای در حال توسعه می دانستند. فرانسمن در سال 1985 خاطر نشان کرد که انتشار تکنولوژی بین المللی از دو نوع معاملات مختلف استفاده می کند. اولی، از نوع معاملات «رسمی» است که شامل سرمایه گذاری مشترک، صدور مجوز و تجارت کالا می باشد. دومین معامله «غیررسمی» است که شامل ارتباط بین شرکت های چند ملیتی (MNEs) و شرکت های محلی و همچنین تبادل علمی می شود که در هر دو حالت، شرکت های چند ملیتی (MNEs) منبع اصلی انتشار تکنولوژی هستند.