Billion Barrels Of Recoverable Oil Research Articles

Reservoir Delineation Employing Spectral Decomposition and Pre-Stack Inversion Techniques, Offshore Nile Delta, Egypt

The Nile Delta occupies the northeastern part of the African continent and it is one of the world’s classic deltas. The present-day delta has passed through different events as part of the regional tectonics in the Mediterranean area which has shaped many of its physiographic features. This area is now regarded as major gas province and one of the most promising areas for future petroleum exploration. In 2010, the U.S. Geological Survey estimated means of 1.8 billion barrels of recoverable oil, 223 trillion cubic feet of recoverable gas, and 6 billion barrels of natural gas liquids in the Nile Delta Basin Province using a geology-based assessment methodology.

Lessons learned from IOR pilots in Bakken formation by using numerical simulation

Bakken is the most productive formation among unconventional plays in North America. This formation has about 7.4 billion barrels of recoverable oil. However, the primary oil recovery is still low as 5–10%. Miscible natural gas and carbon dioxide (CO2) might be the most two potential strategies to improve oil recovery in such a complex play. In this study, some of the IOR pilots which have been conducted in Montana, North Dakota, and South Saskatchewan have been presented. The performance results of these pilots in US-Bakken versus Canadian-Bakken have been compared. Moreover, the reasons behind the successful IOR pilots in Canadian-Bakken versus US-Bakken have been discussed. Then, numerical simulation models have been constructed to mimic the results of some pilots. Two different compositional models have been built for oils of two different formations. Furthermore, two different models, single porosity model and dual permeability model have been created to match the performance of some pilots. Implementation of molecular diffusion mechanism has been conducted in both of single porosity and dual permeability model. Finally, the continuous miscible gases injection versus huff-n-puff protocols have been compared and investigated.The results showed that the performance of natural gases generally over-performed the CO2 injection technique's in Bakken formation. Although the diffusion flow is dominant in these types of reservoirs, the diffusivity of the injected CO2 into formation oil is slow due to the fact that CO2 has large molecules as compared with the small pore throats of these porous media. Accordingly, miscible CO2-EOR might not be beneficial in huff-n-puff operations as in continuous flooding process. However, the success of natural gases based EOR does not have that strong functionality of molar diffusivity. Therefore, their performance was much better than CO2 performance in the field scale of these tight formations. Furthermore, the numerical simulation of this study concluded that the spacing between the production wells and injection wells should be minimized, for the continuous flooding process of miscible-gases EOR, to enhance their performance. Although the permeability of Canadian-Bakken has a permeability of 1–2 order higher than the permeability of US-Bakken, the pilots' spacing between injectors and producers in Canadian Bakken is interestingly much shorter than that for US-Bakken, which might be the reason behind the EOR success in Canadian Bakken. Finally, the activatiown process of the highly intensive natural fractures might be the key to enhance the diffusivity of CO2-EOR. Otherwise, natural gases are highly recommended to be the most potential EOR in these types of reservoirs. This study explains how the diffusion mechanism affects the performance of different miscible gases to improve oil recovery in these plays since they are more complex and very different from conventional formations. Also, it suggests that CO2 flooding process would be a good practice to overcome the limitations of CO2-diffusion rate in these reservoirs if the conformance problems are wisely controlled.

Data analysis for CO2-EOR in shale-oil reservoirs based on a laboratory database

Unconventional resources have played a significant role in changing oil industry plans recently. Shale formations in North America such as Bakken, Niobrara, and Eagle Ford have huge oil in place, 100–900 Billion barrels of recoverable oil in Bakken only. However, the primary oil recovery is still low as 5–10%. EOR methods are currently considered as a new concept in unconventional reservoirs due to the immature information about these plays. Injecting carbon dioxide (CO2) might be the most potential strategy to improve oil recovery in such complex plays (Alfarge et al., 2017a,b).Jin et al. (2016) conducted an experimental study to investigate improving oil recovery by CO2 injection in 21 natural preserved core samples from Bakken Petroleum System (BPS). Their experimental results indicated that CO2 injection has a significant potential to improve oil transportability in these Nano-pores formations. In this study, data analysis for feasibility of CO2-EOR has been conducted on 95 cases of natural preserved cores collected from different formations including 44 cases from Middle Bakken, 26 cases from Lower Bakken, 17 from Upper Bakken, 4 cases from Three Forks, and 4 cases from unknown formation/formations. The relationship between the improved oil recovery by the injected CO2 and 6 rock properties including porosity, permeability, mean pore throat radius, total organic carbon content (TOC), water saturation, and oil saturation has been separately determined and physically discussed. Furthermore, the relationships between the improved oil recovery obtained by the injected CO2 and 4 operating parameters including CO2 bath pressure, CO2 bath temperature, and core sample bulk size, and exposing time have been also separately investigated. A Proxy model to associate the functionality of the improved oil recovery by CO2 injection and these 10 parameters have been constructed. Moreover, statistical methods for Design of Experiments (DOE) have been used to rank the most important parameters affecting CO2-EOR performance in the microscale level (lab scale) of these unconventional reservoirs. This study provides an important set of lab-based data obtained from natural preserved cores to find out the applicability of CO2-EOR in these unconventional reservoirs. Also, this research demonstrates some key points which could help in understanding CO2-EOR mechanisms in shale plays since they are much complex and very different from conventional formations.

Geochemical Characteristics and Modeling of Conventional Petroleum System of Majnoon Oil Field, South Iraq

Organic geochemical analysis and model set–up to simulate the genetic relationships among 18 crude oil samples recovered from different formations and various oil fields within Amara city South Iraq, with depths approximately begin from 2167 to 4430 m, ages of marine carbonates sourced from Middle Jurassic age (Sargelu Formation) according to geochemical similarities appointed previously for this period. The levels of maturation are relatively varied for each sample from low to moderate, MJ-1, MJ-18 (Hartha Formation), MJ-3, MJ-10 (Mishrif Formation), MJ-9 (Nahr Umr Formation), MJ-15 (ZubairFormation), MJ-2, MJ-19(Nahr Umr Formation MJ- 10,MJ-11(Zubair Formation) MJ-3 (Nahr Umr Formation), Mj-3 (Sulaiy Formation), MJ-12 (two samples) Sulaiy Formation MJ-11, MJ-2 (Nahr Umr Formation), MJ-2 (Zubair Formation), MJ-11 (Sulaiy Formation )of Amara city Oil fields.These samples suggest the ages and paleoenvironments of their source rocks. The samples were collected from Upper Jurassic to Cretaceous reservoirs of 18 developed oil fields where about 15 billion barrels of recoverable oil have been reserved.The oil density varies in rather wide range, between 12.2 and 39.2 API. Twelve oil samples are ˂25 API referring to heavy oil and only oil samples attained defiantly from 25 to 35API are medium oil. Canonial Variables (CV) range attain to (- 1.89 to – 3.99) of waxy oil. According to the Tissot and Welte’s classification (1984), most of the oils can be classified as ‘‘high sulfur’’ oils/indicate that these samples are of marine origin.Stable Carbon Isotope Composition C15+ Saturate and Aromatic is relatively approximate values giving good supporting evidences for the same family which is Middle Jurassic Age (sourced from Sargelu Formation), generated within the sedimentation of the bituminous calcareous shale and Limestone in Mesopotamian basin. This basin consider as one of the most formative, potential and promising basin in the Middle East according to the typical petroleum system elements. This family was generated by marine carbonate - intrashelf sub basin source rocks, occurring in Jurassic – Cretaceous – Neogene reservoir rocks of Mesopotamian basin which are geochemically similar to the extracts from Middle –Upper Jurassic age (Sargelu Formations), yielding the majority of petroleum oil and gas fields in north and south Iraq. Petroleum system modeling in one dimension (1-D Petro Mod) was performed using Petro Mod basin modeling software which developed by Integrated Exploration System (IES) to demonstrate burial thermal history hydrocarbon generation and expulsion for Majnoon oil field so that 1-D Petro Mod was applied to Nine wells (Mj-2, Mj-3, Mj-4, Mj-8, Mj-9, Mj-11, Mj-12, Mj-15, and Mj-19) following the procedure of Pitman et al 2004.

Oil and gas at heart of Scotland's future

According to industry, there are between 15 and 24 billion barrels of recoverable oil and gas left under the North sea. It could fund Scotland's future as an independent nation

Niobrara Ramps Up To Hot Play For Liquids

The Niobrara Shale in the United States has ramped up into a hot play that could soon bring an explosion of horizontal drilling in Colorado and Wyoming. The combination of horizontal drilling and multistage hydraulic fracturing is transforming the Niobrara from a target that has been drilled vertically and primarily for gas for nearly 100 years into a liquids-rich play that is capturing considerable attention. Speaking at the 2011 SPE Annual Technical Conference and Exhibition in Denver, John Ford, general manager of Colorado’s Wattenberg field at Anadarko, described the growing Niobrara activity as “really the next big thing.” That optimism was understandable. In November, Anadarko announced that its leases at Wattenberg may hold more than a billion barrels of recoverable oil and natural gas. The statement noted company drilling success in 11 recent wells at the field, including the Dolph 27-1HZ horizontal well that showed initial production of more than 1,100 B/D of oil and 2.4 MMcf/D of natural gas. These latest wells have given the company confidence that it can drill between 1,200 and 2,700 wells in northeast Colorado, with approximately 160 wells planned for this year. Based on results so far, the company expects ultimate recovery of between 500 million and 1.5 billion bbl of oil, natural gas liquids, and natural gas on an equivalent basis. Anadarko is not alone. Chesapeake Energy, Noble, Encana, and EOG Resources are among the largest acreage holders and the most active drillers of many companies—including numerous small independents—probing the Niobrara. Majors such as Shell and Marathon Oil have significant acreage. There are more than 50 operators in or near the Wattenberg field alone. Situated north/northeast of the Denver area, Wattenberg is the largest producing field in the Denver-Julesburg (D-J) Basin and one of the largest onshore oil and gas fields in the US. Reservoir Rock and Producing Regions Although the Niobrara is usually referred to as a shale, its reservoir rock consists primarily of limestone or chalk intervals, said Steve Sonnenberg, professor of petroleum geology at Colorado School of Mines in a recent edition of the AAPG Explorer (published by the American Association of Petroleum Geologists). “The formation demonstrates facies changes that range from limestone and chalk in the eastern end to calcareous shale in the middle and eventually transitioning to sandstone farther west,” said Sonnenberg, a past president of AAPG. “Depth and thickness are highly variable.”

Tectonic-Geophysical Mapping of Israel and the Eastern Mediterranean: Implications for Hydrocarbon Prospecting

The eastern Mediterranean is a tectonically complex region evolving in the long term located in the midst of the progressive Afro-Eurasian collision. Despite years of investigation, its geological-geophysical structure is not completely known. At the same time, the recent discovery of large gas deposits has attracted the attention of many researchers to this region. For instance, the latest U. S. Geological Survey estimates using conventional assessment methodology suggest that there are on the order of 1.7 billion barrels of recoverable oil and more than 4 trillion m3 of recoverable gas in the Levant Basin [1]. This highlights the need for analysis of the paleogeographical conditions that can yield deep paleotectonic criteria for oil and gas discovery in this region. For this purpose, isopach maps of the Middle-Upper Jurassic and Lower Cretaceous were generated from detailed examinations of numerous well sections and the most significant outcroppings in the eastern Mediterranean. The maps confirm an earlier model of continental accretion [2]. In particular, abrupt changes in the trend and thickness of the Early Mesozoic formations coincide with the terrane boundaries. These compiled isopach maps also pinpoint significant distinctions between the Arabian and Sinai plates on the one hand and the Syrian arc on the other. A new tectonic map of the eastern Mediterranean is presented that first of all integrates geophysical satellite-derived gravity and airborne magnetic fields, as well as tectonic-structural, paleogeographical and facial analyses. The results have clear implications for hydrocarbon prospecting in this region.

Chapter 9 Oil and gas resource potential north of the Arctic Circle

Abstract The US Geological Survey recently assessed the potential for undiscovered conventional petroleum in the Arctic. Using a new map compilation of sedimentary elements, the area north of the Arctic Circle was subdivided into 70 assessment units, 48 of which were quantitatively assessed. The Circum-Arctic Resource Appraisal (CARA) was a geologically based, probabilistic study that relied mainly on burial history analysis and analogue modelling to estimate sizes and numbers of undiscovered oil and gas accumulations. The results of the CARA suggest the Arctic is gas-prone with an estimated 770–2990 trillion cubic feet of undiscovered conventional natural gas, most of which is in Russian territory. On an energy-equivalent basis, the quantity of natural gas is more than three times the quantity of oil and the largest undiscovered gas field is expected to be about 10 times the size of the largest undiscovered oil field. In addition to gas, the gas accumulations may contain an estimated 39 billion barrels of liquids. The South Kara Sea is the most prospective gas assessment unit, but giant gas fields containing more than 6 trillion cubic feet of recoverable gas are possible at a 50% chance in 10 assessment units. Sixty per cent of the estimated undiscovered oil resource is in just six assessment units, of which the Alaska Platform, with 31% of the resource, is the most prospective. Overall, the Arctic is estimated to contain between 44 and 157 billion barrels of recoverable oil. Billion barrel oil fields are possible at a 50% chance in seven assessment units. Undiscovered oil resources could be significant to the Arctic nations, but are probably not sufficient to shift the world oil balance away from the Middle East.

Oil Sands Development: A Health Risk Worth Taking?

As traditional petroleum supplies dwindled and prices soared over the past few years, oil companies have shifted their attention to oil sands, a mix of sand, water, and a heavy, viscous hydrocarbon called bitumen that can be converted to oil. With the plunge in oil prices in fall 2008, many producers began canceling or postponing plans to expand oil sands development projects, but this turn of events could yet reverse, as Canada’s vast oil sands deposits are lauded as a secure source of imported oil for the United States. At the same time, however, oil sands present troubling questions in terms of the environmental health effects associated with their development.

Ice wedges of the Dalton Highway, Alaska

North America’s largest oilfield was discovered in 1968 at Prudhoe Bay; it contained over ten billion barrels of recoverable oil about 3000 m beneath the Arctic Coastal Plain. Its development changed Alaska’s economy for ever, and included building the oil pipeline from Prudhoe Bay to Valdez. The haul road alongside the pipeline is still the only road across northern Alaska, and was named the Dalton Highway when it was opened to public access. It crosses the wilderness of the Brooks Range (⇓Fig. 1), and allows completion of a north–south traverse of Alaska, across a broad range of geology and geomorphology; it was the destination for a Geologists’ Association field trip in 1999, when these notes were compiled. Fig. 1. A truck on the Dalton Highway across soliflucted slopes north of the Atigun Pass over the Brooks Range. The two great mountain ranges of Alaska, the Alaska Range in the south and the Brooks Range in the north (⇓Fig. 2), are accumulations of accreted terranes on the convergent plate margins of the Pacific and Arctic Oceans respectively, and both developed major icecaps during the Pleistocene; large glaciers are still fed by Pacific-derived rainfalls on the Alaska Range, but there is none today on the drier Brooks. The intervening Yukon valley and the Arctic Coastal Plain are cold deserts in the mountain rain shadows; they are classic periglacial environments (⇓Ferrians 1994). Their total lack of glaciation throughout the Pleistocene is perhaps most famed for the consequent survival of many rich placer gold deposits, notably in the Klondike valley, just over the border in Canada (⇓Waltham 1995). Fig. 2. Major geomorphological features across Alaska. Permanently frozen ground develops where all the groundwater freezes due to the cooling effect of the air. Continuous permafrost occurs where the mean annual air temperature is lower than about …

Stratigraphic and Lateral Variations of Source Rock Attributes of the Pematang Formation, Central Sumatra: ABSTRACT

The Pematang Formation of the Central Sumatra basin has been shown to be the primary, if not the sole, source for the basin's 10+ billion barrels of recoverable oil. This lacustrine unit, which is restricted to a series of Paleogene half-grabens, typifies the variability present in many rift source rock systems. Differences in organic facies (i.e., level of organic enrichment, kerogen composition, bitumen and product character) occur both stratigraphically and laterally as a result of a series of complex interactions. The stratigraphic controls on organic facies within the Pematang appear to be: (1) the changing relationship between subsidence and sedimentation; (2) long-term climate trends influencing both lake level and regional vegetation patterns; and (3) the evolution of the lake basin's nutrient pool. These controls result in an increase in the level of organic enrichment and oil-proneness toward the top of the unit. Superimposed on this pattern are changes in organic matter content (carbon content) and character (palynofacies, biomarker and isotopic compositions) caused by short-term climatic oscillations. Lateral controls on organic facies can be examined at two different scales - basinal and sub-basinal_ Basinal variations can be related to: (1) different relative subsidence rates among the various sub-basins; and (2) variations in lake water chemistry as a result of the nature of the paleodrainage basin. On a sub­ basinal scale organic facies appear to be controlled by: (1) hydrodynamic processes and basin circulation; and (2) variations in water depth. These lateral variations are manifested in the level of organic enrichment, the relative proportions of oil- and gas-prone kerogen, and variations in oil composition.

Human Disturbances of Denning Polar Bears in Alaska

Polar bears ( Ursus maritimus ) give birth in dens of snow and ice. The altricial neonates cannot leave the den for >2 months post-partum and are potentially vulnerable to disturbances near dens. The coastal plain (1002) area of Alaska's Arctic National Wildlife Refuge (ANWR) lies in a region of known polar bear denning and also may contain >9 billion barrels of recoverable oil. Polar bears in dens could be affected in many ways by hydrocarbon development, but neither the distribution of dens nor the sensitivity of bears in dens has been known. I documented the distribution of dens on ANWR between 1981 and 1992 and observed responses of bears in dens to various anthropogenic disturbances. Of 44 dens located by radiotelemetry on the mainland coast of Alaska and Canada, 20 (45%) were on ANWR and 15 (34%) were within the 1002 area. Thus, development of ANWR will increase the potential that denning polar bears are disturbed by human activities. However, perturbations resulting from capture, marking, and radiotracking maternal bears did not affect litter sizes or stature of cubs produced. Likewise, 10 of 12 denned polar bears tolerated exposure to exceptional levels of activity. This tolerance and the fact that investment in the denning effort increases through the winter indicated that spatial and temporal restrictions on developments could prevent the potential for many disruptions of denned bears from being realized. Key words: Alaska, ANWR, Arctic, denning, disturbance, impact, oil development, polar bear, reproduction, Ursus maritimus

About this title

The Middle Jurassic Brent Group sediments, and their correlatives on the Norwegian Shelf are, in economic terms, the most important hydrocarbon reservoir in NW Europe. In 1971 the Brent Field was discovered by Shell/Esso and tested in 1972 with 1.8 billion barrels of recoverable oil. By 1988 discovered Brent hydrocarbons comprised some 490f the UK’s recoverable reserves, totalling 22.5 billion barrels of oil equivalent. Now that the UK Brent Province has reached maturity, this book provides a comprehensive review of the geology and petroleum geology of one of the world’s major petroleum reservoirs. With the contents covering exploration history, structural evolution, sequence stratigraphy, sedimentology, diagenests, palynology, hydrocarbon generation and migration, and petrophysics, the book will be of interest to geoscientists in many fields especially petroleum geologists, sedimentologists, petrophysicists and biostratigraphers.

The Production of Jet Fuel From Alternative Sources

The most significant potential source of aviation gas turbine fuels in the continental United States is the western oil shale located in the Rocky Mountain States of Colorado, Utah, and Wyoming. Nearly 600 billion barrels of recoverable oil is located in this area. This paper discusses the availability of oil shale and reviews the recovery, upgrading and refining schemes necessary to produce fuel which can be used in present-day aircraft. Other synthetic fuels are discussed with regard to the processing necessary to produce suitable fuels for today’s high-performance aircraft. Heavy oil and tar sand bitumen are likely to be refined in the next decade. Methods for producing suitable fuels are discussed. The chemical structure of these sources, which is basically cyclic, leads to the potential for heavier fuels with more energy per given volume and therefore longer range for certain aircraft. This exciting possibility is reviewed.

Character of Ancient Petroliferous Lake Basins of the World: ABSTRACT

The principal oil- and gas-bearing lacustrine rocks in the world were formed from sediments deposited in or peripheral to ancient stratified lakes, of a variety of ages, which for millions of years maintained a size comparable to that of modern inland seas. In these lake systems, both lipid and woody organic matter were developed and preserved in large quantities. The lacustrine rock system commonly constitutes a depositional complex that includes indigenous hydrocarbon source, reservoir, and trap units. Lacustrine strata of China consist primarily of siliciclastic rocks; those of Brazil, Angola, and Cabinda are principally of siliciclastic rocks with abundant carbonate units; those of the End_Page 1680------------------------------ United States consist of at least 50% carbonate rock. Hydrocarbon resources of lacustrine depositional systems are greatest in the People's Republic of China (several billion barrels of recoverable oil). Hydrocarbon resources are also significant in the ancient lake basins of Brazil, Angola, Cabinda, and United States. Currently developed Chinese oil fields in nonmarine rocks are primarily in structural traps, those of South America and Africa are in combination structural and stratigraphic traps, whereas those of the United States are principally in stratigraphic traps. Available data suggest that hydrocarbons in the more deeply buried strata are contained in secondary pores which received oil or gas subsequent to significant episodes of cementation and/or compaction, and dissolution of minerals. Reservoir rocks with abundant primary porosity are most commonly preserved at relatively shallow burial depths, and many are intercalated with immature source units. Primary pores contain hydrocarbons that have migrated to reservoirs from mature source rocks (more deeply buried?). In China, oil is recovered in great quantities from sandstones with abundant primary porosity, particularly in those basins with high geothermal gradients. The oil apparently migrated to the primary pores from nearby source beds which reached thermochemical maturation at relatively shallow depths of burial and before significant early cementation and compaction of the sandstone units. Matrix porosity and permeability in sandstone units are best developed and preserved in those rocks composed of chemically stable minerals and few labile grains. Fluid-pressure gradients may be abnormally high in those lacustrine systems that have reached the stage of thermochemical maturation. In these cases, oil and/or gas are generated and expelled in quantities great enough to locally increase fluid pressures faster than pressure is released to adjoining rocks. Abnormally high fluid-pressure gradients in lacustrine units also occur in those impermeable hydrocarbon-bearing strata that have apparently been elevated at a rapid rate. In such a system, equilibration between fluid pressures in beds of low matrix permeability in the deep subsurface and permeable beds near the surface is restricted. In both cases, fractured overpressured rocks of low matrix permeability may yield oil and/or gas from pools whose boundaries are not restricted to loc l structures. Rather, they are restricted by relatively permeable beds that have provided access to the surface for pressure and fluid release (and invasion of water). Local avenues of permeability in overpressured rocks are greatest along natural, open fractures. Although reservoir rocks for fields developed in lake basins are commonly described as being of a lacustrine origin, others were formed from sediment deposited at the edge of a lake or in settings well removed from a lake. Principal reservoir rocks in the Uinta basin, Utah, represent the basal parts of coalesced fluvial channels formed at the fluctuating margin of lake Uinta. Red-colored oil-bearing strata in some Chinese fields whose reservoir rocks are channel-fill sandstones formed from sediment deposited on an alluvial plain several kilometers from the lacustrine shoreline. Lacustrine turbidite, bar, and deltaic rocks are important reservoirs in Brazil, Africa, United States, and China. Petroliferous sedimentary rocks formed in lake basins are known over much of the world where th y contain many billion barrels of recoverable oil and offer the promise of more. End_of_Article - Last_Page 1681------------

WATER FOR OIL SHALE1

Although there may be as many as 600 billion barrels of recoverable oil locked up in the shale formations of the Rocky Mountains, the price of extraction of this oil will be high. The oil companies are unanimous in their view that the enormous risks involved in developing the industry should not be borne by the companies alone. Some kind of government subsidy, they say, is essential. A large scale oil shale industry will also have significant effects upon the clean air, water, and unique quality of life on the west slope of Colorado. A carefully constructed decision-making process is needed in order to make fundamental resource allocation decisions. The paper approaches the problem of development vs. the environment--by looking at one piece of it: water-intensive energy development in an arid rural area, in hopes of shedding some light on the range of institutional alternatives for making resource allocation decisions. The first section deals with the region itself; its resources and water supply capability, and at the projected impacts of a fully developed oil shale industry on the water resource. Then, with this context, the final section presents several examples of institutional allocation mechanisms that may suggest a conceptual rangemore » of approaches to resource allocation problems. (GMC)« less

History of Oil Development in Libya: ABSTRACT

Concessions were first granted in Libya during late 1955. At that time 14 companies obtained concessions totaling 130 million acres. By November 19, 1959, concession areas had increased to 265 million acres, but they decreased to 174 million acres by September 1, 1965. On July 29, 1965, 98 individual blocks totaling 147,589,617 acres were made available for bidding. As of September 1, 1965, no additional acreage had been granted. Exploration activity has been concentrated in two basins. Of primary interest is the Sirte basin in east-central Libya. Since drilling activities commenced in 1956, 1,572 wells have been completed in Libya, of which 44 per cent were wildcats. In the Sirte basin 12 per cent of the wildcat wells have been successful, and in the Ghadames basin of western Libya 18 per cent have been successful. No oil has been found in the Murzuck or Cufra basins. More than 11 million feet of hole has been drilled, 4.84 million feet of which has been wildcat drilling. Eighty-five oil fields, 59 in the Sirte basin and 26 in the Ghadames basin, have been discovered by means of wildcat drilling. It is estimated that more than 9 billion barrels of oil in place have been found. Individual pool reserves range from a few thousand barrels to more than one billion barrels of recoverable oil. The largest reserves are in Eocene and Cretaceous rocks of the Sirte basin. At the end of 1961, one company was producing at the rate of 40 thousand barrels per day. Today five companies are producing more than 1.25 million barrels per day. Industry has spent over 1.3 billion dollars in the search for oil, increasing from 33 million dollars in 1957 to more than 270 million dollars in 1964. End_of_Article - Last_Page 635------------

Williston Basin Developments, 1951-1953: ABSTRACT

The phenomenal rate of development in the Williston basin can best be visualized by remembering that at the end of 1950 there was not one producing oil well within the basin parts of North Dakota, South Dakota, Montana, Saskatchewan, or Manitoba. During three years of unprecedented exploratory drilling which followed the first commercial production of oil in the Williston basin (Virden field, T. 10 N., R. 28 WPM., Manitoba, Canada), 55 oil fields, 20 field extensions, and 4 gas fields have been discovered. During this period, production has been established from 16 different formations. One of the most spectacular discoveries during this period came in August, 1953, when End_Page 945------------------------------ flush production at 2,100 feet was developed in the Lodgepole (Mississippian) in the Roselea field, 56 miles north of the North Dakota line in Manitoba. Subsequent wells in the Roselea field have reported initials as high as 2,500 barrels of oil per day. The lack of sufficient well information makes it impractical to calculate the reserves represented by the fields thus far discovered; however, the most conservative estimate places this figure between 500 million and 1 billion barrels of recoverable oil. The year 1953 witnessed the completion of the 300,000 barrels per day Interprovincial Pipe Line from Edmonton, Alberta, to Sarnia, Ontario, and marked the beginning of construction of three new refineries in North Dakota, which on completion will process 33,500 barrels of basin crude daily. 1953 also saw the completion of the 100,000-barrel-per-day common carrier Service Pipe Line from the Beaver Lodge-Tioga area to Mandan, North Dakota, the beginning of construction of a natural-gasoline plant at Tioga, North Dakota, and the completion of Stanolind's products line from Mandan to Fargo, North Dakota. There remains, however, an urgent need for additional marketing facilities before the full economic potential of the basin can be realized. Judged from recent official and unofficial anno ncements, plans to create new facilities are under way and the next five years should show marked progress in this direction. With geophysical activity maintaining its record-breaking pace, and millions of acres of leases approaching one year closer to the expiration date of their primary terms, it is expected that 1954 will witness an unprecedented wildcat and field development program in the Williston basin. Excellent shallow production in Manitoba, the discovery of the first commercial oil in South Dakota, plus continued success in Montana, North Dakota, and Saskatchewan will serve as an incentive to substantiate this 1954 prediction. End_of_Article - Last_Page 946------------