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This paper examines the impact of oil resources endowment, measured by proven reserves and oil rents, on the economic growth in the presence of quality of governance factors. To address this issue,...

Summary Proven reserves of «traditional» oil are on a declining trend. Therefore, it is necessary for producing companies to consider hard-to-recover reserves as a resource base in the future. Currently, the term «hard-to-recover reserves» is not defined enough. Some categories of the hard-to-recover reserves may be deleted from this list due to the development of technology, making the production of hydrocarbons much easier. However, an exploration of subsurface using modern technology makes it possible to produce these hydrocarbon reserves. That was impossible previously. The examples are the production of Permian petroleum bitumen and the development of domanic formations.

Carbonate oil and gas reserves account for more than 50% of the world’s proven reserves and more than 60% of the world’s production. The marine sedimentary rocks, mainly concentrated in Tarim, Ordos and Sichuan basins, are widely distributed in China covering an area of 4.5 million km2. The amount of oil and gas resources is abundant, and the proved reserves are still increasing as exploration extends. However, China has found such reservoirs difficult to produce: deep burial, poor matrix permeability, significant reservoir heterogeneity and weak oil and water regularity are typical reservoir characteristics. At present, the standard primary recovery factor is only 16.4%. The authors first reviewed the classification and characteristics of the marine carbonate rocks in China. We then took Tarim Oilfield as the main analysis target, reviewed its exploration and production history in the past 20 years and the current situation. We summarized the major production problems and the technical countermeasures that has proved effective in improving the oil recovery in the fractured-cavernous carbonate reservoir. These technologies include fine geological modeling, unit division, connectivity evaluation, dynamic reserve evaluation, numerical simulation, unit displacement by water and gas injection, etc. This work summarizes the field experience, breakthroughs and key technologies from Tarim Field. The understandings help engineers in designing of technological processes for fractured-cavernous reservoir and improve oil recovery in similar carbonate reservoirs.

Summary Proven reserves of «traditional» oil are on a declining trend. Therefore, it is necessary for producing companies to consider hard-to-recover reserves as a resource base in the future. Currently, the term «hard-to-recover reserves» is not defined enough. Some categories of the hard-to-recover reserves may be deleted from this list due to the development of technology, making the production of hydrocarbons much easier. However, an exploration of subsurface using modern technology makes it possible to produce these hydrocarbon reserves. That was impossible previously. The examples are the production of Permian petroleum bitumen and the development of domanic formations.

Due to usage of fossil fuels, the depletion of world crude oil reserves and increased deteriorating climate conditions have reached a high level. These circumstances have led researches to search for alternative and efficient fuels. The main biofuels considered are bioethanol and biodiesel. In this study, ethanol and biodiesel production from cotton stalk and seed were aimed using liquid hot water (LHW) along with consecutive processes, where separate saccharification and fermentation (SHF) process was carried out. The maximum ethanol concentrations of 0.348 g/L and 0.721 g/L were achieved at 24 h and 72 h, respectively. For biodiesel conversion, cottonseed oil was subjected to transesterification, where the main interest was to utilize the by-product, glycerol. Three different glycerol concentrations were investigated in terms of ethanol fermentation using Escherichia coli K1 active culture. The maximum ethanol concentration of 0.415 g/L was achieved at 20 mL glycerol concentration for 48 h. Overall, cotton stalk and seed have the potential to be utilized on an industrial scale. © 2019, Springer-Verlag GmbH Germany, part of Springer Nature.

Formation water can in principal be used to identify hydrocarbon reserves. One such potential reserves are the gas reservoirs in the Ordos basin in China. However, there is limited data for this basin; we thus investigated the geochemical properties of a large range of formation water acquired from the Ordovician in the Ordos basin (42 brine samples obtained from different wells at M5 member) and analyzed their chemical characteristics. The results showed that this formation water is associated with a sealed reservoir, which is good for hydrocarbon storage. This is also related to the demonstrated strong diagenetic transformations. We also proposed statistical relationships between these geochemical properties and hydrocarbon storage based on a machine learning method (Decision tree). The results suggest that the salinity, Na+/Cl− ratio, (Cl−-Na+)/Mg2+ ratio, (HCO3−-CO32-)/Ca2+ ratio and Mg2+/Ca2+ ratio highly correlate with the gas preservation. The results thus provide drastically more accurate predictions in terms of where to find gas reservoirs in the Ordos basin, and can thus lead to significantly better exploitation of these resources.

Based on a comprehensive analysis, the geological and geochemical characteristics of large gas fields in China were summarized in this paper. By the end of 2011, altogether 48 large gas fields had been discovered in China, with their proven reserves accounting for 81.5% of the total proven gas reserves in China. The main geological and geochemical characteristics of large gas fields in China are as follows: (1) Alkane gases are the main components of natural gas, with an average methane content of 88.22%, and the average contents of ethane, propane and butane of 3.31%, 0.97% and 0.49%, respectively; (2) The natural gases in 27 of the 48 large gas fields are coal-derived gases which indicate coal-derived gas is the major genetic type of natural gas in China; (3) Reservoirs are in multiple strata, but natural gas is mostly produced from the Permian and Triassic; Sandstones, carbonates and volcanics are the main reservoirs, of which the sandstones have the most reserves; (4) There are 16 tight gas fields in the 48 large gas fields, suggesting the crucial importance of this type of reservoirs in China; (5) Most of these large gas fields were formed at late or very late stages, suggesting late reservoir formation is favorable for gas preservation; (6) Multiple reservoir types are identified, including structural, lithologic and stratigraphic reservoirs. Key words: China, large gas field, geological characteristics, geochemical characteristics, coal-derived gas, oil-type gas

Coalbed gas, also called coalbed methane gas, is a kind of unconventional natural gas located in coal and rocks, coexisting with coal and its main ingredient are methane. On different levels of structure, coal bed methanes adsorption has partition zonality. The gas-bearing of coal seams has relative concentration in different tectonic units, is known as coalbed methane (CBM) enrichment. Influenced by coal rank, coal, rock properties and various geological conditions and other factors, the enrichment has certain regularity. In the study of the coal bed gas enrichment, coal bed gas enrichment especially refers to coal bed methane enrichment. Economic evaluation is that it may analysis reserves financial feasibility and economical rationality for coal seam to get the best economic benefit evaluation, by various stages in CBM cost and final production and income situation.

The world now relies almost exclusively on petroleum products to power our transportation systems, and coal, natural gas, nuclear and some petroleum products along with a small but growing contribution from renewables for most electricity production. The petroleum dependence is hazardous since approximately 82.6 % of all petroleum proven reserves reside in the twelve OPEC nations (Algeria, Angola, Ecuador, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, UAE, Venezuela) based predominantly in the volatile Middle East. (The ten Middle East and North African nations (excluding Ecuador and Venezuela) still account for 72.2% of all proved petroleum reserves). Coal, on the other hand, is widely distributed around the globe, and natural gas is more widely distributed than petroleum. OPEC nations account for at most 3.7 % of proven coal reserves. We conclude that moving to a global energy system based predominantly on coal instead of petroleum would be far more stable for world security.

The Crepuscular Earth presented here is a guess reference model of the planet in which all mineral resources have been extracted and dispersed and fossil fuels have been burnt. It serves as a realistic limit of resources to assess the Earth’s non-renewable exergy capital. Under such conditions we estimate a state of the atmosphere and hydrosphere using updated fossil fuels stocks (1925 GtC for proven reserves, rising to about 16,224 GtC when including estimated additional reserves) and emissions projections in a simple model of the carbon cycle. We consider the BAU-I scenario as the most likely to occur, corresponding to an atmospheric injection of about 2000 GtC. Accordingly, we propose a crepuscular atmosphere having a carbon dioxide content of 683 ppm, a mean surface temperature of 17 °C (peak carbon dioxide induced warming of 3.7 °C above pre-industrial temperatures), a pressure of 1.021 bar, and a composition in volume basis of 78.8% N 2 , 20.92% O 2 , 0.93% Ar, and 0.0015% of trace gases. Considering that oceans account for 97.5% of the whole hydrosphere, the crepuscular hydrosphere is assumed to have the current chemical composition of the oceans at an average temperature of 17 °C.

In the 80’s of last century, based on the advances in natural gas exploration practice, the concepts of bio-thermocatalytic transitional-zone gas and early thermogenetic gas were proposed, and the lower limit Ro values for the formation and accumulation of thermogenetic natural gases of industrial importance have been extended to 0.3%–0.4%. In accordance with the two-stage model established on the basis of carbon isotope fractionation involved in the formation of coal-type natural gases, the upper limit Ro values of lowly evolved natural gases should be set at 0.8%–1.0%. This is the concept of low-mature gas which is commonly accepted at the present time. The Urengoy super-large gas field in western Siberian Basin is a typical example of low-mature gas field, where low-mature gas reserves account for 20% of the globally proven natural gas reserves, and this fully indicates the importance of this kind of resources. The proven reserves of natural gases in the Turpan-Hami Basin of China are approximate to 1000×108 m3, and the thermal evolution indices of source rocks are Ro=0.4%–0.8%. The δ13C1 values of methane are mainly within the range of −44‰–39‰ (corresponding to Ro=0.6%–0.8%), and those of ethane are mainly within the range of −29‰–26‰, indicating that these natural gases should be designated to the coal-type low-mature gases. The light hydrocarbon evolution indices of natural gases also provide strong evidence suggesting that they are the coal-type low-mature gases. If so, low-mature gas in the Turpan-Hami Basin has been accumulated to such an extent as to be equivalent to the total reserves of three large-sized gas fields, and their existence is of great significance in the study and exploration of China’s low-mature gases. If it is evidenced that the source rocks of low-mature gases are related mainly to coal measures, China’s abundant lowly evolved coal series resources will provide a huge resource potentiality for the generation of low-mature gases.

This paper examines global oil resources and the future global oil supply/demand balance. The paper builds upon several comprehensive databases designed during the work and considerable efforts have been made to review what must be considered the most reliable data. Global oil resources have been investigated on three levels; country, company and field levels. Although no decisive conclusions or quantitative assessments can be made with respect to the global oil resource base, remaining resources appear to be sufficient to meet demand up to 2030 as projected in the 2006 (and 2007) world energy outlook by the IEA. Significant resources have already been discovered beyond proven reserves, many prospective regions remain to be fully explored and there are vast volumes of recoverable unconventional oil. However, it is also concluded that global supply of oil probably will continue to be tight, both in the medium term as well as in the long term mainly as a consequence of above-ground factors such as investment constraints, geopolitical tensions, limited access to reserves and mature super-giant fields. Production of unconventional oil and synthetic fuels is not believed to significantly alter this situation. Although an increasing number of recent reports have indicated an imminent or “soon to come” peak in global oil supply, it has not been found that any of these reports have contributed with any new information on oil resources or oil supply ability. Nevertheless, there is a distinct possibility that global oil production may peak or plateau in a relatively near future, not caused by limited resources but because too many factors over long time constrain investments into exploration and production. The lack of transparency within the oil industry obviously prevents any accurate analysis of future production and supply ability. Moreover, our ability to analyse the sector will become more difficult in the future as oil increasingly will have to be sourced from countries with a poor transparency. The world will become increasingly dependent on a few countries in the Middle East and on Russia not only for the supply of oil but also for the supply of gas which to a large extent will be utilised for power and heat generation. A responsible policy should under these circumstances seek to enhance energy security which should be directed towards promoting energy efficiency measures (reduce demand) in combination with increased utilisation of indigenous fuel resources such as renewables and fossil fuels in combination with CO2 capture and storage. Such a policy would both facilitate the transmission to a more sustainable energy system in the future as well as enhance energy security.

Zonguldak coal basin is the only productive hard coal basin of Turkey. The eastern part of the basin is called as Bartin–Amasra District, which has deeper coal seams. The depth and difficulty of mining these coal seams make this district an important candidate for coalbed methane (CBM) recovery. However, there is not enough reservoir data for modeling purposes. In this study, the lithologic information collected for coal mining industry was used to determine the correlations and the continuity of the coal seams. The lithologic information was examined and the depths of the coal seams and the locations of the exploration boreholes were used to perform a reliable correlation using a new method. As a result of the correlation study, 63 continuous coal layers were found. A statistical reserve estimation of each coal layer for methane was made by using Monte Carlo simulation method. The initial methane in place found in the coal layers both in free and adsorbed states were estimated using probabilistic simulations resulted in possible reserve (P10) of 2.07 billion m 3 , probable reserve (P50) of 1.35 billion m 3 and proven reserves (P90) of 0.86 billion m 3 . Among the determined continuous coal layers, coal layer #26 was selected for a preliminary investigation of the applicability of enhanced coalbed methane (ECBM) recovery and CO 2 storage. The scarcity of coal seam reservoir data required a sensitivity study for the effects of reservoir parameters on operational performance indicators. The effects of adsorption, coal density, permeability, cleat porosity and permeability anisotropy parameters were examined using the Computer Modeling Group's (CMG) GEM module.

No natural gas pool of industrial importance could be formed at the low-evolution stage of organic matter. In the 1980s, on the basis of the development in exploration practice, the hypotheses of bio-thermo-catalytic transitional zone gases and early thermogenic gases were proposed. The lower-limit Ro values for the formation and accumulation of natural gases of industrial importance have been expanded to 0.3%–0.4%. In the light of the two-stage model established on the basis of carbon isotope fractionation in coal-type natural gases, the upper-limit Ro values have been set at 0.8%–1.0%. In terms of the geological practice in the low-mature gas zones and China’s main coal-type gas fields, it is feasible and proper to set the upper-limit Ro value of low-mature gases at 0.8%. Supper-large gas fields such as the Urengoy gas field in western Siberian Basin should belong to low-mature gas fields, of which the natural gas reserves account for more than 20% of the global proven reserves, providing strong evidence for the significance of such a type of resources. The proven natural gas reserves in the Turpan-Hami Basin of China have almost reached 1000 ×108 m3. The main source rocks in this area are the Jurassic Xishanyao Formation, which occurs as a suite of coal series strata. The corresponding thermal evolution indices (Ro) are mainly within the range of about 0.4%–0.8%, the δ13C1 values of methane vary between −44‰ and −39‰ (correspondingly Ro =0.6%–0.8%), and those of ethane are within the range of −29‰–−26‰, indicating that natural gases in the Turpan-Hami Basin should be designated to coal-type low-mature gases. The light hydrocarbon evolution indices of natural gases also fall within the area of low evolution while the precursor type of light hydrocarbons also shows the characteristics of the coal-type. The geological background, carbon isotopic composition and light hydrocarbon index all provide strong evidence suggesting that the proven natural gases in the Turpan-Hami Basin are low-mature gases. In China a gas field with the gas reserves reaching 300 ×108 m3 can be defined as a large gas field, and thus the proven low-mature gases in the Turpan-Hami Basin are equivalent to the reserves of three large gas fields. Its existence is of great significance in research on and exploration of low-mature gases in China.

Natural gas is produced from the fossilization of microscopic plants that were formed during the Carboniferous period, around 300 million years ago. Over time the gas has migrated from the rocks in which it was formed, often collecting in reservoirs beneath impervious rock caps. Conventional gas reserves from these reservoirs will normally flow to the surface once the reservoir is accessed. Gas is trapped within other rocks and can only be released by hydraulic fracturing. The main constituent of natural gas is methane but it can contain a range of other higher hydrocarbons. Proved natural reserves are around 190 trillion m 3 but total reserves are certainly much larger. The Middle East and Russia hold the largest total national and regional reserves. The largest national producer and consumer of natural gas is the United States.

Introduction The U.S. economy consumes large amounts of imported oil. In 2006, U.S. oil consumption was about 20 million barrels per day (mbd), with domestic production a little over 8mbd. This gap of 12mbd (which has been growing since the 1970s) is 60 percent of U.S. consumption, with rising levels of imports making up the difference. Increased demand from countries like China and India has been associated with world oil prices rising to unprecedented levels. This has led to increased investment and production from higher-cost sources such as Canada's oil sands. With conventional oil production peaking or declining in many countries, the vast potential of oil extraction from tar sand becomes commercially viable. Political instability in the Persian Gulf and Nigeria makes security of the oil supply chain an increasingly significant concern for the U.S. Since oil is priced in U.S. dollars, Canadian exports of oil sand petroleum will not be affected by the strong Canadian dollar (which is approaching parity with the U.S. dollar for the first time in decades). In the short run, gasoline demand is not very responsive to price changes, so the underlying demand conditions should remain consistent. Only a severe U.S. and worldwide recession (an unlikely prospect) would cause a sharp drop in oil prices. Therefore, conditions remain favorable for the continued development of the Canadian oil sands. This essay reviews the increased significance of oil extracted from the Athabasca tar sands, located primarily in Alberta. As production ramped up from this nonconventional source, the "tar sands" became the "oil sands." This narrative will proceed as follows: first, a review of current levels of production and proven reserves; second, the importance of Canadian oil exports to the United States; third, the increased presence of Asian nations, especially China, in Canadian oil sand production; fourth, the possible impact of Canada-Asia oil business on Canada-U.S. relations; fifth, recognition of the environmental challenges associated with oil sand development; and sixth, some conclusions about the long-term impacts of these developments. Oil Sands A recent article in the New York Times stated that "Iraq's proven oil reserves stand at about 115 billion barrels, the world's third largest after Saudi Arabia and Iran" (Sept. 10, 2006). While this statement may be correct when counting conventional sources of oil, Canadian reserves should be ranked second, bumping down Iran and Iraq, when the oil sands are included. Since 2003, the Canadian oil sands have generally been included in total proven Canadian oil reserves. Overnight, this increased Canada's proven reserves from 5 billion to 180 billion barrels (Chastko 2004, xiii). As noted above, this places Canada second in the world to Saudi Arabia. Oil sand estimates, conservatively based on recoverable reserves using current technology, represent only 11 percent of the estimated 1.6 trillion barrels of tar sand oil in Alberta. In terms of actual production--what was recovered rather than what was recoverable--Canada was the eighth largest oil producer in the world in 2004 (Energy Information Administration [EIA] 2005). As improved technology allows for increased recovery rates, it is only a matter of time before Canadian reserves become the largest in the world. Oil sand production is expected to rise from current levels of 1 million barrels a day (mbd) to over 3mbd by 2015. While most output will be shipped to the U.S., some will be sold to China and other Asian nations. Oil exports have become increasingly important to Canada. Canada continues to enjoy an overall balance of trade surplus, especially with the United States, but has a deficit with most Asian countries, including China. While Canadian exports to the U.S. finally reached year 2000 levels once more in 2004, after a reduction following the tragedy of 9/11, these aggregate numbers hide the fact that foreign sales were flat or down in most categories--e. …

We assess the financial determinants of Canadian oil and gas company stock returns. We find that the return of Canadian energy stock is positively associated with the Canadian stock market return, with appreciations of crude oil and natural gas prices, with growth in internal cash flows and proven reserves, and negatively with interest rates. Surprisingly, however, production volume and a weakening of the Canadian dollar against the US dollar have a negative impact. This latter impact is more pronounced for oil producers than for integrated energy companies. Finally, we find that the influence of the exchange rate, the market return and prices of natural gas on Canadian oil and gas stocks changes significantly over the years 1995–1998 and 2000–2002.

Venezuelan oil diplomacy has long been a factor shaping the international energy regime, and domestic political conflicts in Venezuela have always interacted synergistically with conflict over the global energy system. So it is the case with intense domestic conflicts that have swirled around President Hugo Chavez, the country's controversial populist leader. Partly at stake is whether the rules of the global oil regime will correspond to a neoliberal framework permitting freer access to minerals and hydrocarbons on the part of capital, or whether national sovereignty continues to legitimate host countries' right to regulate access and demand compensation for exploitation of natural resources. Are the resources in a sovereign nation's subsoil a free gift of nature that lie worthless without the application of labour and investment, or do they constitute exhaustible "natural wealth" for which the nation is entitled to compensation? This question recurs in debates over the imposition of royalty, participation in OPEC, management of state-owned enterprises, and foreign participation in different phases of the industry.Venezuela ranks sixth in the world in proven reserves of conventional crudes, with 78 billion barrels.1 235 billion barrels of heavy oil (at an eight percent recovery rate) in the Orinoco tar belt can be added to this total. At a 30 percent rate of recovery, the oil ministry estimates Venezuela's total reserves at 700 billion barrels, more than proven reserves in the entire Middle East. Impractical today, such reserves might become attractive if most global oil fields have passed "peak" rates of recovery, global demand continues to increase, and technological improvements in emulsifying heavy oils are made. In addition, Venezuela has the world's ninth largest reserve of natural gas, trailing only the US in the Western hemisphere. Venezuela consistently ranks in the top five exporters of oil to the US market.Oil powers Venezuelan diplomacy. Deliveries of oil on credit helped Argentine President Nestor Kirchner face down the International Monetary Fund in 2003-04. Venezuela experts are advising other Latin governments, including Colombia and Bolivia, on contracts with foreign investors. Oil money funds Telesur, a Venezuelan-initiated, hemispheric television network. Petrosur is Venezuela's effort to create a South American oil company; PetroCaribe provides discounted oil to countries in the Caribbean Basin. Oil diplomacy has helped Chavez obstruct the US initiative for a NAFTA-like free trade area of the Americas and promote his "Bolivarian alternative for the Americas," which prioritizes social objectives and regional integration.VENEZUELA AND GLOBAL OIL REGIMESVenezuela's leadership in shaping third world oil policies arose in part from the consequences of the Mexican revolution. Mexico was the first third world country to nationalize foreign oil companies (in 1938), but consequently the foreign majors excluded PEMEX production from global markets until the 19705, when Mexican oil was welcomed back as part of an effort to counterbalance the Organization of Petroleum Exporting Countries (OPEC). In 1943, because of political space opened by Mexican nationalization, the companies accepted a new oil law revising generous concessions of the past and acknowledging that their profits are subject to Venezuela's sovereign powers of taxation. A few years later, the Venezuelan government and Standard oil agreed to stabilize each side's share of profits at 50 percent. American companies promoted this "50-50" agreement in the Middle East, helping them muscle their way into subsoil previously the preserve of European companies. Illustrating how transitory such agreements can be, in 1958 a Venezuelan government, facing a difficult economic situation inherited from a recently deposed dictatorship, unilaterally raised taxes.Venezuela's advantage as a low-cost producer was diminishing as the country began shakily in 1959 what would be its first extended period of democratic rule. …

The landscape of the global sector has undergone a massive transformation as “Big Oil” has been replaced with national oil companies, but one issue remains in question: the role of the West. Controlling approximately 70 percent of the world’s proven reserves, the national oil companies that comprise the Organization of Petroleum Exporting Countries (OPEC) must reconcile the legacy of their colonial past with their future success in the post-colonial world. OPEC’s two largest exporters, Saudi Arabia and Iran, have a starkly different relationship with the West that has ultimately affected present-day realities of their oil companies as well as the ability of these petro-states to govern. This article first examines the impact of Western influence on Saudi Arabian and Iranian nationalization narratives and identifies key drivers that have encouraged Saudi Arabia’s open cooperation with the West, while simultaneously fostering Iran’s isolationism. The paper subsequently analyzes the impact of these relationships on Saudi Arabian and Iranian oil governance, ultimately suggesting that greater Western influence tends to better overall governance. With the rise of national oil companies the shift towards symbiotic mutualism has become a necessary means for national oil companies to establish sustainable oil governance in a post-colonial context.

The amount of proven reserves of oil sands in Canada is estimated to be 175 billion barrels, placing the deposit second in the world in size. Even if the production increases to the same peak level as the North Sea, the R/P ratio is still 80 years, showing the richness of the oil sands resource. The current combination of, the advantageous location adjacent to the extensive U.S. market, with established infrastructure for transportation, the decrease of development and production costs as a result of improved technology, and the recent rise in oil prices are attracting many investors to oil sands development. Canada Oil Sands Co., Ltd. (CANOS), through its subsidiary JACOS, started the pursuit of commercial bitumen production in 1978. After decades of technical trials, CANOS has implemented the SAGD method in 1997 and started production in 1999. It is currently producing 8,000 to 9,000 b/d of bitumen. Throughout its operation history, CANOS has faced many technical challenges and significant advances have been made. These challenges include; ·Application of horizontal well drilling technology. ·Proving the efficiency of the SAGD mechanism. ·Improving G&G evaluation accuracy using sequence stratigraphic framework and 3D seismic data. ·Improving reservoir evaluation quality with the help of sector models and 3D simulation models. ·Optimization of operations including improvement of steam-oil ratio. ·Analysis of volatile pricing of diluted bitumen. SAGD is a new innovative technology and requires the integration of various technical fields. With continuing room for improvement, SAGD offers challenging but worthwhile opportunities for geoscientists and petroleum engineers. The attractive investment environment resembles that of the North Sea development in its early days. In the North Sea, Japanese companies were at a disadvantage as late-comers. CANOS, on the other hand is, and plans to stay on the leading edge of Canadian oil sands development.

The discovery of Alpine Field has renewed industry interest in oil exploration within the National Petroleum Reserve-Alaska (NPRA). Alpine Field, near the northeast border of the NPRA, is the first commercial production from the Jurassic sands within the Kingak Shale. It is estimated to contain in excess of 400 million barrels of proven reserves and, according to the U.S. Geological Survey, the stratigraphic conditions found at Alpine are likely to extend across the northern portion of the NPRA. Over the last several years, geophysical companies have collected 3D seismic data along the expected Alpine trend.

This paper shows that there is a strict quantitative connection between three factors: reserves-to-production ratio (w), rate of production growth (a), and degree of reserve replenishment during 1 year (i). The first of these factors shows how many years the current level of production can be supported by existing proved reserves (if both are invariable). The second factor shows how quickly the production increases. The third, characterizes the correlation between oil production and reserves discovery, which is the basis for potential oil production growth. For planning purposes it is important to know how many units of new reserves have to be proved during each year per one unit of production for the different reserves-to-production ratio and production growth. The results of calculating these factors are shown in the table and pictured on the graph. They can be used for regions where the replenishment of proven reserves (factor (i)) exceeds 1 barrel of new reserves per 1 barrel of production. This paper also describes the interdependence and dynamics of these factors when the replenishment of proved reserves is incomplete.

The US Department of Energy's Energy Information Administration (EIA) recently predicted that world oil production could continue to increase for more than three decades, based on the recent US Geological Survey (USGS) evaluation of world oil resources and a simple, transparent model. However, it can be shown that this model is not consistent with actual oil production records in many different regions, particularly that of the US, from which it was derived. A more careful application of the EIA model, using the same resource estimates, indicates that at best non-OPEC oil production can increase for less than two decades, and should begin to decline at the latest sometime between 2015 and 2020. OPEC at this point will completely control the world oil market and will need to meet increased demand as well as compensate for declining production of non-OPEC producers. OPEC could control the market even sooner than this, given its larger share of proven oil reserves, probable difficulties in transforming non-OPEC undiscovered reserves into proven reserves, and the converging interests of all oil producers as reserves are depleted. This has significant implications for the world economy and for US national security.

The study presented here examined a Kuwaiti reservoir that is classified as a next-generation extreme heavy oil tar-mat reservoir. Successful pyrolysis experiments were performed on carbonate rock containing 33.51% total organic content (TOC). Comparable toluene solvent, water extraction, and surfactant solution extraction had successful but different hydrocarbon recovery yields under different temperature settings. The tar-mat flow was extremely viscous, with a measured "API density close to 1.34 and calculated flow mobility close to zero. Depending on the type of extracting agent applied, increasing the temperature cracked the extreme heavy oil tar-mat available in the carbonate rock, hence improving the extremely viscous nature of the solid residue and causing it to be mobile so that it could flow and be recovered. Four carbon-density flow regimes were identified in this extreme heavy oil tar-mat composition mix, including the free hydrocarbon type I composition (C1–C15), the light hydrocarbon type II composition (C15–C40), the heavy hydrocarbon type III composition (>C40), and the insoluble carbon-residue type IV material (NSO). Each flow regime exhibited a unique recovery potential within the extremely viscous composition mix. A detailed characterization of this tar-mat sample confirmed that the release of trapped type I, type II, and type III compositions from the carbonate pore space was possible, while type IV residue remained resistant to flow, and hydrocarbon retention on the rock was difficult to overcome with the suggested recovery treatments.

Trinidad & Tobago ~10°N,61°W!, a British colony until 1962, is an upper-to-middle income country in the Caribbean and as of the year 2000 has an estimated population of 1.3 million, a literacy rate of approximately 95% ~World 2000!, and a land area of 5,128 km ~Trinidad—4,828 km and Tobago—300 km!. The larger island of Trinidad has 95% of the population, and Tobago, which is mountainous and has a small tourist industry, is economically dependent on Trinidad. Trinidad & Tobago, henceforth referred to as the island, has ample water resources, arable land ~Shrivastava, unpublished research report, 2001!, and large proven reserves of oil and natural gas, which are estimated to be approximately 716 million barrels and 23.4 trillion cubic feet, respectively ~Radler 2002!. Specifically, the island is currently the world’s leading exporter of both ammonia and methanol, which are derived from natural gas, and the largest exporter of liquefied natural gas to the United States ~Alexander Oil & Gas 2002!. Simply put, the island has a classic petroleum economy, dangerously dependent on oil and gas earnings, and—due to the neglect of agriculture—almost totally dependent on the importation of food. Further, it has a poor transportation infrastructure, and there is a strong need to regenerate urban areas. Accordingly, there are plans for major expansion and modernization of the irrigation, drainage, transportation, and urban infrastructure for addressing these socioeconomic issues ~GORTT 1997; Halcrow 2000; and Trinidad Guardian 2002a!. This forum presents, against this likelihood of considerable civil engineering activity in the foreseeable future, some professional issues in civil engineering education, training, and practice in the island.

Conventional hydrocarbon resources have been associated with pre-Devonian petroleum systems across the globe, including the Neoproterozoic–Infracambrian Huqf Supergroup of the Oman basin, the Riphean - Vendian sequences of East Siberia, the Cambrian of the Sirte basin, the Ordovician of the Tarim basin, and the Silurian Qasaiba of Saudi Arabia. Although individual accumulations can be quite significant (e.g., Hassi Messaoud has proven reserves of ~6.4 billion barrels), the relative importance of pre-Devonian-derived oils is limited compared to the global conventional resource-base. With growing interest in unconventional resources, the relative importance of these systems is expected to increase as plays such as the Ordovician Utica Shale of the Appalachian basin, the Cambrian of China, and the Silurian of Central and Eastern Europe develop.

A phosphate mining waste, called Feral is produced during the processing of a phosphate rich alumina (25wt% P2O5, 27wt% Al2O3, 9.53 wt% Fe2O3) which makes up the Lam-Lam deposit in western Senegal (Fig. 1). Lam-Lam is one of the few aluminium phosphate deposits in the world. These unweathered Al-phosphates are mined by the Societe Senegalaise des Phosphates de Taiba (SSPT) near the village of Lam Lam, northwest of Thies. These phosphates occur as 7 m thick layers under a thick iron crust. Proven reserves of this deposit are 4 million tones of marketable product with an average grade of 33% P2O5. Only 1.5 million tones of these reserves have an overburden of less than 24 m (McClellan and Notholt 1986).

In recent years, with its sustained and rapid economic development, the contradiction between supply and demand on China's petroleum is daily outstanding, and it makes the dependence rate of foreign oil resources going higher and higher. With the method of time series analysis and based on the data of China's oil self-sufficiency and proven reserves from 1980 to 2009, ARIMA models which is used for forecasting China's oil self-sufficiency in this paper is established, and solutions to deal with the oil problem are proposed.

With a sustained growth rate of 6.2%, India is set to become the third largest economy following the USA and Chinaby 2035. In accordance with the growth rate, it is estimated that India's import dependence is likely to increase from the current level of 72% to approximately 90% by 2035. With a large dependency on imports to meet commercial energy requirements, the demand/supply gap in oil and gas in Indiawill inevitably grow.Unconventional energy resources are becoming increasingly more important in the quest for energy security because of the continuing decline of production from proven reserves (4 to 6% decline has been observed in mature fields), accompanied by the increasing price of crude oil and natural gas. Potential sources of unconventional energyin India, proven or speculated, are coalbed methane (CBM), shale oil/gas, tight gas, and gas hydrates. With the recent advancement in 3D seismic analysis and technologies developed to analyze core samples, these have enabled a better understanding of CBM fields and other unconventional reservoirs. Because of the low permeability of these formations, economical production from unconventional reserves can only be obtained using a hydraulic-fracturing stimulation technique. Advancements in fracturing techniques from the conventional “perf-and-plug” method to multistage fracturing have enabled stimulation treatments in long intervals in a rapid and cost-effective manner. The use of advanced and proven numerical simulators in designing hydraulic-fracturing treatments has exponentially increased the success of treatments. Development of cleaner and environmentally acceptable fluids for stimulation treatments has reduced formation damage and is critical for effective stimulation of these unconventional sources of energy. Case studies from Indian fields where such emerging and effective technologies are being implemented are presented. Best practices developed to exploit CBM reservoirs and lessons learned from the mature fields in overcoming several operational challenges are discussed. Introduction India, an emerging economy, has undergone unprecedented levels of economic expansion, along with countries like China, Russia, Mexico, and Brazil. With a gross domestic product (GDP) growth rate of 8.8% in Q1 2010, by 2035 India is set to become the third largest economy following the USA and China, assuming the forecasted compounded annual growth rate (CAGR) of 6.2%. The GDP of India grew from USD 36 billion to 1.25 trillion over the last five decades. This expansion increased primary energy consumption in India by about 5% (CAGR) over the last two decades; whereas, for the rest of the world, this increase was only 2% (CAGR). Indiacomprises 16% of the total world population and,with a CAGR of 1.54%, it is expected to cross 1.5 billion by 2035; therefore, energy will be one of the most critical aspects supporting the economy and human development. According to British Petroleum statistics (BP Statistical Review of World Energy), India has only 0.4% of the world’s proven oil reserves and 0.6% of the world’s natural gas reserves. With the current rate of oil production, these proven reserves will meet the needs of the Indian economy for 20 or more years.The demand/supply mismatch for oil and gas is inevitable, and India's dependence on imported hydrocarbons is likely to increase from its current level. To cope with increasingly active manufacturing and production sectors, and the rising per capita energy consumption, Indiamust strategically rebuild and shift its energy consumption portfolio. Tackling the energy crisis through judicious use of abundantly available renewable energy resources, such as biomass, solar, and wind energy, and unconventional oil and gas sources, must be given the highest priority. In 2009, only 5.9% of the total energy requirement was met through

Oil exploration in Israel began in 1953. Until 1991 a total of 263 exploration wells and 122 development wells were drilled, 3 oil fields and 5 gas fields were discovered, and 4 noncommercial oil discoveries and 1 noncommercial gas discovery were made. Proven in-place reserves amount to 70 million barrels of oil equivalent (MMBOE). Exploration focused on six main plays: Syrian Arc anticlines; Mesozoic platform-edge, structural-stratigraphic traps; the Dead Sea graben; Early Mesozoic structures; Saqiye Group biogenic gas; and Hula Group biogenic gas. The more significant discoveries are associated with the first two plays. Ninety percent of the proven reserves were discovered by the first 71 wildcats, which constitute 27 percent of all wildcats drilled to date. During this phase of exploration, the average success was 7 percent, and the average discovery rate was 0.88 MMBOE per wildcat. Most of the following 192 wildcats were dry holes. If, as experts claim, significant reserves are still undiscovered, previous exploration must be deemed inefficient. The quantitative model of the discovery process also leads to such an assessment.

The Southern Permian Basin (also referred to as Central European Basin) is Europe s largest sedimentary basin. It is a typical intracontinental basin that evolved from latest Carboniferous to recent times and extends from eastern England to the Belarussian-Polish border and from Denmark to South Germany. The Southern Permian Basin Atlas (SPBA) project is a joint project between the Geological Surveys of Belgium, Denmark, Germany, The Netherlands, Poland, and the UK and is being supported by a wide range of E&P companies, government licensing authorities, universities and research institutes. The aim of the Atlas is to present an overview of the results of over 150 years of petroleum exploration and research in this basin area. As this gas and oil province continues to mature and with field sizes inevitably decreasing, more and more careful data integration and geoscientific effort is required to discover new reserves. The subsurface characterization provided in the Atlas will also be of great value to governments, researchers and other individuals interested in the deep subsurface.

The objective of this project is to eliminate three closely inter-related barriers to oil production in Alaska through the use of a geographic information system (GIS) and other information technology strategies. These barriers involve identification of oil development potential from existing wells, planning projects to efficiently avoid conflicts with other interests, and gaining state approvals for exploration and development projects. Each barrier is the result of either current labor-intensive methods or poorly accessible information. This project brings together three parts of the oil exploration, development, and permitting process to form the foundation for a more fully integrated information technology infrastructure for the State of Alaska. This web-based system will enable the public and other review participants to track permit status, submit and view comments, and obtain important project information online. By automating several functions of the current manual process, permit applications will be completed more quickly and accurately, and agencies will be able to complete reviews with fewer delays. The application will include an on-line diagnostic Coastal Project Questionnaire to determine the suite of permits required for a specific project. The application will also automatically create distribution lists based on the location and type of project, populate document templates for project review start-ups, public notices and findings, allow submission of e-comments, and post project status information on the Internet. Alaska has nearly one-quarter of the nation's supply of crude oil, at least five billion barrels of proven reserves. The American Association of Petroleum Geologists report that the 1995 National Assessment identified the North Slope as having 7.4 billion barrels of technically recoverable oil and over 63 trillion cubic feet of natural gas. From these reserves, Alaska produces roughly one-fifth of the nation's daily crude oil production, or approximately one million barrels per day from over 1,800 active wells. Currently, State of Alaska agencies use multiple, independent systems to identify, authenticate, and authorize customers for online transactions. Consumers of online state services may be required to manage multiple online ''profiles,'' and during a permit review process valuable time may be lost verifying identity or reconciling differences in applicant information when agency records disagree. The state's Information Technology Group is developing a shared applicant profile system that will provide an additional opportunity to demonstrate data sharing between agencies.

This chapter elaborates on the hydrocarbon habitat of the Middle East. The presence of hydrocarbons in the Middle East has been known since historic times, and they have been used in a variety of ways. The chapter reports that the Pitch was used by the Sumerians not only for waterproofing, but also as a bonding material in construction. The magnitude of the petroleum potential in the Middle East is so well-known that little documentation is required. The only areas with production and potential approaching that of the Middle East are in the Pricaspian Basin and the West Siberian Basin of the former USSR. Saudi Arabia ranks second in proven reserves and first in exporting oil, replacing the former Soviet Union with its rapidly declining production. The combination of a number of factors—such as the accumulation of a thick sequence of sediments; the presence of excellent reservoir rocks (mainly carbonates); the wide, regional distribution of seals; the close association of reservoirs with the intrashelf, basinal source rocks; and the excellent, large anticlinal traps with extraordinarily wide closure—have contributed to the hydrocarbon richness of the Middle East.

This report summarizes data produced as part of a U.S. Department of Energy (DOE) project to evaluate methods for improving waterflood response in the Upper Cretaceous D sandstone of the Denver basin. Historically poor performance of waterflooding in this widespread reservoir has meant total recoveries averaging less than 20% of original oil in place (OOIP), with considerable variation in local sweep efficiency. Detailed reservoir characterization of the D sandstone in the Sooner unit, integrating well-log, core, seismic, and engineering data, resulted in an updated reservoir model that included delineation of multiple reservoir compartments. This model was used as a basis for a field redevelopment plan whose initial stage involved realigning existing injectors/producers and drilling several infill locations to increase sweep efficiency on a compartment-by-compartment basis. Results of implementation included a 100% increase in daily unit production, an increase in proven reserves of 696,000 bbl oil equivalent to more than 10% of OOIP. On the basis of these results, ultimate recovery from the unit, with implementation of selective infill drilling, is projected at 32.6% OOIP. Success of the project © Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Petroleum Consultant, 1511 18th Avenue East, Seattle, Washington 98112. Grateful acknowledgment is expressed to Mark Sippel of Mark Sippel Engineering (Denver, Colorado) for providing data and expertise essential to the writing of this report. Appreciation is also extended to Floyd Bardsley for artwork.Send reprint requests to AAPG Publications Manager, P.O. Box 979, Tulsa, Oklahoma 74101-0979. M = million, G = billion.

Using a dual approach of basic research and applied field-optimization studies, Bureau geoscientists are helping industry maximize the recovery of oil and gas in stratigraphically complex reservoirs. Basic research on reservoir architecture is supported by two industrial associates programs that are evaluating siliciclastic reservoirs (Characterization of Heterogeneity Style and Permeability Structure in a Sequence Stratigraphic Framework in Fluvial-Deltaic Reservoirs) and carbonate reservoirs (Characterization of Carbonate Reservoirs) by combining outcrop analogs of major reservoir types and subsurface reservoir studies. In these two programs, high-frequency sequence stratigraphic analysis--along with analyses of rock fabric, permeability structure, bounding surfaces, and reservoir stacking patterns-is being evaluated in order to simulate interwell heterogeneity and its effect on fluid flow. Results are transferred to more than 25 companies worldwide through workshops, field courses, mentor programs, reports, journal articles, preprints and data sets. Research results from oil and gas field-optimization studies in North America, South America, and Australia have combined play assessment, detailed sequence stratigraphic and depositional-system analyses, and reservoir characterization to strategically deploy technology and achieve reserve growth in fields that have been producing for as long as 50 years. Geocellullar modeling and three-dimensional visualization of geologic, petrophysical, and engineering data are critical to establishing accurate estimatesmore » of original oil in place and remaining mobile oil. Reservoir settings, including tide-dominated deltaic, shelf, fluvial, and lacustrine-delta depositional systems, have been targeted for new infield wells, recompletions, and step-out locations. Proven reserves of more than 450 million barrels of remaining mobile oil have been identified in one field optimization study.« less

The world's use of oil, the relationship of world population growth to this use, and what the energy situation might be in the future is a challenge to the geologist. The earth's population doubled between 1930 and 1975 and a comparison of world petroleum use and population growth show similar upward curves. Of the annual fossil fuel resources used in the world, crude oil supplies over 40 percent of the total resources. Petroleum is a finite resource and a projection of world oil production indicates it will peak early in the 21st century. Assuming an ultimate recovery range of 2600 to 3000 billion barrels of oil, 750 billion barrels have already been produced, there are 1000 billion barrels in proven reserves, and 1000 billion barrels remaining to be discovered. The challenge to the geologist will be to find these hidden oil reserves. Recovering this 1000 billion barrels of new oil reserves will require large capital expenditures and, currently, only 60 percent of the capital needed to discover this oil is being spent. With the world's demand for oil increasing, world-wide exploration expenditures are actually decreasing. Simple economics indicates that the reason for this drop in expenditures is that the pricemore » of oil is too low to encourage investment. Low oil prices also discourage investment in the development of alternative fuels. There is plenty of oil now, but the world must look to the future and realize present usage rate cannot continue forever. 23 refs., 10 figs.« less

Exploration for hydrocarbons started in 1965. The first commercial discovery (Ekofisk) was made in 1969, leading to the first production of hydrocarbons in 1971. Later, a large number of oil and gas fields were discovered, 19 of which were in production by June 1989. A number of new fields will be developed in the next decade. The anticipated production level by mid-1990 is approximately 90 million tons of oil equivalent as oil and approximately 30 million tons of oil equivalent as gas. Proven reserves for the whole of the Norwegian continental shelf as of June 1989 were estimated at 5,200 million tons of oil equivalent, of which approximately 2,100 million tons are oil and approximately 3,100 million tons are gas. Most of these reserves (60%) lie in giant fields. All the giants discovered are either already in production or in the development phase. Most of the big fields were discovered from 1978 to 1985. Exploration Costs are increasing as a function of the fact that most Of the recent discoveries are smaller than previously discovered fields. Exploration costs, however, are still low in Norway compared to most other areas. The R/P ratio for Norway is approximately 20 for oil andmore » approximately 120 for gas. The remaining unproven potential of the Norwegian continental shelf is expected to be at least 4 billion tons of oil equivalent, of which 70% or more is anticipated to be gas. New reserves will have to be found in the North Sea, outside mid-Norway, and in the Barents Sea. The challenge for Norway in the future will be to discover new oil fields, make the smaller oil fields already discovered economically viable, enhance oil recovery from existing fields, and find markets for our large gas reserves. Norway will remain a major oil-producing nation well into the next century, and a major gas-producing nation for a much longer period.« less

Annual additions to proven oil reserves are used to analyze yield per effort (YPE) between 1946 and 1989 in the lower 48 United States. YPE is the amount of oil added to reserves per foot of oil well drilled. The YPE data are used in a regression model that shows YPE is determined by long-term factors such as depletion and technical change, and short-term factors such as changes in the drilling rate, changes in the importance of revisions to oil reserves, and shifts between the intensive and extensive margin of exploration and development. When the short-term determinants of YPE are accounted for, YPE shows a significant exponential decline during the past 45 years. If the rate of drilling remains at the level it was in the late 1980s, the model projects about 21 billion bl of oil will be added to proven reserves from 1990 to 2010 in the lower 48 United States. Maintaining a drilling rate twice that of the late 1980s will add 29 billion bbl of oil to the proven reserves. Those projections suggest that proven oil reserves in the lower 48 United States will decrease sharply, with the magnitude of the decrease dependent also on the rate of oil production. The results also show that the expansion of exploration in the Gulf of Mexico did not alter significantly the overall decline in YPE for the entire lower 48 United States.

This paper first explains the substantial weakening of the arrangements that have given national oil companies in the OPEC countries exclusive access to their oil reserves. Although those members of OPEC with large reserves - the Gulf countries and Venezuela - manage to preserve the old system, that is not the case for member countries which have difficulty in maintaining their production and proven reserves. The second part of the paper sets out the new international arrangements that have taken shape in the upstream portion of the world all industry. It highlights what is happening in the important all-producing developing countries, and the potential and the uncertainty involved in cooperative agreements with the former Soviet Union.

Departing from Hotelling’s assumption of fixed and known reserves, this paper develops an economic model of additions to proven reserves that explicitly incorporates the effects of expected resource price, cumulative reserves development, and technological progress on reserve additions. The model treats additions to proven oil reserves as output of a production process in which drilling wells is a primary input to transform some of oil-in-place into the economic category of proven reserves. Application of the model to US data for the 1950–1995 period provides strong statistical support for the existence of all the three salient effects. We obtain an estimate of the price elasticity of reserve additions (absent from previous studies) which, although statistically highly significant, is rather small. Using this price elasticity estimate, it is shown that if in the face of steady economic growth, and hence, oil consumption, US oil import dependence is to be kept from rising in the future, ceteris paribus, a steady oil price increase in the range of 1.5–4.5% a year is essential.

Canada is a country rich in petroleum. Not only has it been, for many years, the only country in the western world totally self‐sufficient in production, it has also been able to supply a healthy export market. For many years discoveries of new oil exceeded consumption, and substantial proven reserves were accumulated. In spite of this rather considerable development of production, only one major basin has been explored to any substantial degree, and only a fraction of the total oil believed to lie in place has been discovered to date. Provinces with oil reserves have prospered under stable, equitable legislation that fostered substantial expenditures of funds for exploration (Figure 1 ).

This paper addresses the following question — does the number of proven petroleum reserves on the Norwegian continental shelf justify the current level of exploratory effort? The paper argues that this effort should be curtailed for some time to come. It also provides a framework within which the recurrent problem of selecting an appropriate level of exploratory effort can be analysed.

The authors have made an estimate of global oil and gas potential, using methods applicable to such estimates in the USSR, and then have differentiated the resources on the basis of production costs. The geological resources of oil in foreign (excluding socialist) countries are estimated at approximately 1.2 trillion tons. Of this quantity, about 473 billion tons are technically extractable (not allowing for costs). At the beginning of 1984, the current (residual) extractable resources were about 415 billion tons, of which 35% applied to resources of exploitable deposits, including 20% in proven reserves. Of the total amount of current extractable reserves of oil, about 36% constituted resources which may be exploited with costs of up to $45 per ton (US), including 22% with costs of less than $10 per ton. The gas potential of foreign countries (except socialist) has been estimated at 565 trillion m/sup 3/. Of this, about 350 trillion m/sup 3/ are technically extractable (without consideration of cost). At the beginning of 1984, the current gas resources were 318 trillion m/sup 3/, of which 17% were confined to exploitable deposits. More than half of the gas resources which may be exploited at costs not greater than $10/1000 m/supmore » 3/ (US), have already been discovered. Again, 47 trillion m/sup 3/ may be exploited at costs of $10-45/1000 m/sup 3/ and 19 trillion m/sup 3/ at $45-80/1000 m/sup 3/, that is, a total of 112 trillion m/sup 3/, of which about 48% are concentrated in already-discovered deposits. About 206 trillion fall in the category of very expensive gas. These are as yet mainly undiscovered resources in remote, polar, and deepwater regions. 4 references.« less

Passive-margin sedimentary basins, despite their geologic similarities, differ substantially in their oil and gas reserves and in the distributions of these areally and in the section. Evidently, the level of hydrocarbon potential is controlled by differences in the size and history of the zone of petroleum generation. This conclusion was originally drawn from historical methods applied to various basins. To refine the conclusions and define the significance of the individual factors controlling hydrocarbon generation, it is of interest to examine the petroleum potential for a fairly extensive system. Here the authors consider the Morocco basin, in the passive-margin basin system of the East Atlantic, which has very scanty oil and gas reserves. The proven reserves at the start of 1978 were only 20.55 million metric tons of oil and 1.2 billion m/sup 3/ of gas. 16 references.

The first part of this paper aims to establish the regional distribution of ultimate resources of conventional oil and to assess the size of future discoveries and their share in the renewal of world oil resources. The authors use a synthesis of seven recent studies as their starting point. This analysis suggests that in the long run it will be difficult to bring about a significant and durable reduction in the importance of the Arabo-Persian Gulf on the international petroleum scene. The study also presents a tentative breakdown of ultimate oil resources in terms of production costs, proven reserves, future discoveries and additional quantities, directly arising from technical and cost progress in enhanced oil recovery methods. The authors conclude that the Middle East and planned economy countries account for nearly 60% of ultimate oil resources exploitable at a cost of less than $20/bbl and that more than half of the resources available in the rest of the world are exploitable at more than $12/bbl.

The Persian Gulf region is one of the richest parts of the world in terms of oil and gas resources (Fig. 1). In 1979, proven oil reserves in the Persian Gulf amounted to 365 billion barrels, equal to 82% of OPEC’s and 53% of the world’s proven reserves. In terms of proven gas reserves, the Persian Gulf nations’ reserves amounted to 20.4 trillion m3 or 75% of OPEC’s and 29% of the world’s proven gas reserves. In 1979, Persian Gulf exports accounted for nearly 60% of the world trade in petroleum. Six of the major oil producers within OPEC border the Persian Gulf (Saudi Arabia, Iran, Iraq, Kuwait, Qatar, and the United Arab Emirates [UAE]). Despite its importance, the Persian Gulf region is a highly politicized and unstable region. Kuwait, Oman, and the UAE (comprised of seven tiny sheikdoms) are city states or emirates with very small populations. Iran still suffers from the after-shocks of its 1979 revolution and Saudi Arabia and Iraq suffer from domestic political problems. The nations of this region belong to different ideological camps. Border conflicts, claims to each other’s territories and internal political pressures make another political flare-up in the area with consequent impact on oil production and exports a dangerous possibility. Notwithstanding the differences and instabilities, the oil nations of the Persian Gulf have, in most cases, resolved their differences in matters related to oil. In some cases, where diplomatic relations were at the breaking point, the oil ministers, within the OPEC framework, coordinated their policies in a mutually beneficial manner. However, difficulties were a little greater where offshore joint developments of oilfields were concerned.

This chapter focuses on one country—Iran—where oil consumption historically has been by far the highest among the organization of the petroleum exporting countries (OPEC). Iran is rich in oil resources; its proven reserves have been estimated at just less than 60 billion barrels but the actual figure is much higher. Iran's future conduct with regard to the development of its natural gas resources is potentially very significant as its vast resources can make it one of the world's major exporters of this source of clean, safe, and versatile energy. Iran's posture toward nuclear power is watched closely, in part because a decision to resume construction of two nearly completed reactors may be prompted by a desire to acquire an Islamic bomb—an outcome that, however impractical, is sure to send strategic shock waves throughout the Middle East and beyond, and is sure to revive the discussion over the relationship between the spread of civilian nuclear power and nuclear weapons proliferation. Moreover, Iran's decision to scale down its once ambitious petrochemical program has affected not only the future course of its own industrialization but also its potential petrochemical customers and competitors.

This paper describes the three year history of an independent oil company formed to purchase and enhance producing properties. The application of detailed field studies and conventional enhancement techniques has resulted in increased proven reserves and substantially increased cash flow from the properties in spite of the decline in oil prices. Total investment in the properties to through 1982 was $41.3 million with an additional $16 million remaining to be spent if all identified enhancement projects are implemented. Pre-tax rates of return for the total acquisition program are expected to be in the 24 to 28 percent range.

Eighty-three sedimentary basins cover 50% of Africa's 11.7 million square miles. Hydrocarbons are produced from 20 of these basins and a further 13 have non-produced hydrocarbons. Yet of all the basins, only 18% have been explored through a semi-mature stage. This paper presents a simplified classification of basins in Africa. Africa's recoverable hydrocarbon reserves of 100 billion barrels of oil equivalent account for 7% of the world's total, proven reserves. This paper documents that reserve base's development through time together with the significant discoveries. Oil and gas occurrences and the play potential of each basin type are systematically described, with examples demonstrating exploration problems regarding particular basins. Africa contains an abundance of unexplored sedimentary basins that should demonstrate relatively high success ratios but which must be evaluated with some caution because of political, fiscal, and logistical concerns. End_Page 339

Interest in the efficient utilization of gaseous fuel resources for the production of power using conventional internal combustion engines, has been increasing worldwide in view of the inevitable declining resources of petroleum and projected limitations on the availability of refined liquid fuels, particularly those of the right quality. This is in contrast to statements made that the proven reserves of natural gas are increasing1 and that there are potentially enormous reserves of natural gas2 that can be utilized as fuels in engine applications. Moreover, there is increased perceived availability of other forms of gaseous fuels such as liquid petroleum gases, gas fuel mixtures produced from the processing and upgrading of various fossil fuel resources such as coal, oil sands and shales and from the processing of organic and vegetable wastes in the form of bio-gas.