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This study proposes a new method for estimating tight oil resources in a closed petroleum system using an alternative mass balance model. The proposed approach primarily derives resource estimates based on a large volume of Rock-Eval pyrolysis data. In addition to leveraging the cost-effective, straightforward, and rapid process, the proposed method has the flexibility to assess the potential of different types of resources, including organic-rich tight (shale) oil and organic-lean tight oil. The method is validated by assessing the oil resource potential of the middle Permian Lucaogou Formation (P2l) in the Jimusaer depression, Junggar Basin, China. Results indicate that the P2l contains 1.62 × 109 t (11.91 × 109 bbl) of organic-rich and 2.88 × 109 t (21.17 × 109 bbl) of organic-lean tight oil. Of the organic-rich tight oil, 21% comprises free oil resources, amounting to 0.343 × 109 t (2.521 × 109 bbl). The proposed approach deals sufficiently with the different resources in a petroleum system well and provides a useful tool for estimating the resource potential of an unconventional play.

The Mississippian Barnett Shale within the Bend arch–Fort Worth Basin is a major continuous shale-gas resource in the United States. The Barnett Shale was last assessed by the US Geological Survey (USGS) in 2003 and only included vertical drilling. The Barnett Shale was reassessed in 2015 for undiscovered, technically recoverable gas and oil resources to include the impact of over 12 yr of horizontal-drilling development. The 2015 USGS assessment delineated three continuous assessment units (AUs): (1) Barnett Continuous Gas AU, (2) Barnett Mixed Continuous Gas and Oil AU, and (3) Western Barnett Continuous Oil AU. The AU boundaries were defined by hydrogen index (HI) values as a proxy for thermal maturity, in addition to shale thickness. An HI value of 100 mg hydrocarbon (HC)/g total organic carbon (TOC) was used to define the Barnett Continuous Gas AU boundary. The Barnett Mixed Continuous Gas and Oil AU was defined within the northeastern part of the basin where HI values are greater than 100 mg HC/g TOC and the shale thickness exceeds 100 ft (31 m). Resulting undiscovered, technically recoverable resource estimates for these two AUs were 53 tcf of gas, 172 million bbl of oil, and 176 million bbl of natural gas liquids. The western part of the Barnett Shale (HI >100) comprises the Western Barnett Continuous Oil AU, and it was not quantitatively assessed. The recent USGS assessment is nearly double the 2003 mean resource estimate of 26.2 tcf of gas and is the first study to provide quantitative estimates for shale-oil resources in the Barnett Shale.

Exploration and production (EP) efforts represent repeated trials involving many uncertain ventures, so a statistical treatment of the associated undiscovered resources is appropriate. However, when we consider the required reporting of proved reserves after a specific discovery, we are currently required to specify a volume of hydrocarbons that we are reasonably certain will be economically recovered from wells associated with that discovery. The phrase reasonable certainty is a probability statement, except that no confidence level is specified by the governing authorities. Company appraisers may be influenced that larger estimates (if defendable) benefit the value of their company shares and perhaps their status in a company, whereas various negative consequences may ensue if actual outcome turns out to be smaller than the reasonably certain estimate. We view this clash of probabilistic methods versus determinism as an illogical professional conundrum. Because deterministic parameters are not probabilistically specified, a professional's estimating ability cannot be properly measured and calibrated. Without a rigorous process for reality checking, this approach encourages unrealistic thinking about uncertain resource values and thus can facilitate technical and financial unaccountability. In fact, ill-defined standards can actually encourage unethical behavior through confusion and manipulation, obscuring boundaries between professional objectivity and conflicting incentive systems. The solution can be complex because of the many factors associated with uncertainty in subsurface parameters, product prices, government takes, and capital costs. However, the solution can be addressed by full disclosure, plus the development of a unified standard within the EP community of probabilistic reserve definitions for proved,probable, and possible reserves. Full disclosure of probabilistic reserve estimates will (1) facilitate the reality checking of estimates against analogs and natural limits, (2) help measure estimating accuracy against actual outcomes, (3) encourage improvements in future estimating accuracy and efficiency, and (4) provide transparency to the public. Until more uniform standards are developed and enforced, EP entities will continue to use resource numbers beyond the proved level as a basis for decision making, as they are more relevant for the business planning and portfolio management of their shareholders' assets.

Productive carbonate buildups of Pennsylvanian age in the southern Paradox basin, Utah, contain up to 200 million bbl remaining oil potentially recoverable by enhanced recovery methods. These buildups comprise over 100 satellite fields to the giant Greater Aneth field, where secondary recovery operations thus far have been concentrated. Several types of satellite buildups exist and produce oil from the Desert Creek zone of the Paradox Formation. Many of the relevant fields have undergone early abandonment; wells in Desert Creek carbonate mounds commonly produce at very high initial rates (>1000 bbl/day) and then suffer precipitous declines. An important new study focused on the detailed characterization of five separate reservoirs has resulted in significant information relevant to their future redevelopment. Completed assessment of Anasazi field suggests that phylloid algal mounds, the major productive buildup type in this area, consist of ten separate lithotypes and can be described in terms of a two-level reservoir system with an underlying high-permeability mound-core interval overlain by a lower permeability but volumetrically larger supramound (mound capping) interval. Reservoir simulations and related performance predictions indicate that CO2 flooding of these reservoirs should have considerable success in recovering remaining oil reserves.

Although the majority of the oil reserves contained in the Ninian field are being produced from tilted Middle Jurassic sandstones of the Brent Group, significant volumes of oil have also been discovered within a poorly documented, subtle structural trap that lies in the immediate footwall to the field's controlling, eastern boundary fault. Integration of well data and the interpretation of seismic surveys allow the definition of an area characterized by major footwall degradation. The data demonstrate that the 1.25-mi (2-km) wide area affected lies to the east of the zone of Brent Group truncation, along the whole 15-mi (25-km) length of the field. A combination of sedimentary and stratigraphic information shows that the degradation and products obtain a thickness that locally exceeds 450 ft (126 m). The degradation process appears to have been triggered by accelerated extension during the Callovian-early Oxfordian deposition of the Heather Formation. The development of pronounced fault terraces due to footwall collapse ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received February 26, 1996; revised manuscript received August 12, 1996; final acceptance December 24, 1996. 2Department of Geology and Geophysics, The University of Edinburgh, Kings Buildings, West Mains Road, Edinburgh, EH9 3JW Scotland; e-mail: jru@glg.ed.ac.uk 3Chevron (UK) Ltd., Ninian House, Crawpeel Road, Aberdeen, AB12 3LG Scotland. 4Department of Earth Sciences, University of Manchester, Oxford Road, Manchester, M13 9PL England. We would like to thank the Ninian Partners [Chevron UK Ltd., Murphy Petroleum Ltd., Oryx UK Energy Company, Sands Petroleum (formerly NESTE North Sea Ltd.), Sun Oil Britain Ltd., and Ranger Oil] for permission to publish this article. However, the views expressed here are ours and are not necessarily those of Chevron or the Ninian Partnership. Help was received from Rick Davis, Robert Heming, Bryan Man, Bill Higgs, Andrew Harding, and John Connor of Chevron. Gerry White is thanked for drafting the diagrams. Interpretations carried out using GeoQuest ies and iesx software mounted on Edinburgh's Seismic Workstation facility were supported by The Petroleum Science and Technology Institute (PSTI), Norsk Hydro, Shell Expro, and Esso Exploration and Production (UK) Ltd. The study forms part of a wider research program studying the occurrence and effects of fault scarp degradation and subtle stratigraphic trap formation in the Brent province currently being supported at The University of Edinburgh by a Natural Environmental Research Council (NERC) Realising Our Potential Award (ROPA) Grant, GR3/R9521. Finally, we would like to acknowledge AAPG reviewers Alan Roberts and J. Brint for helpful and constructive comments.

The principles of capillary pressure and hydrodynamic flow can be useful for exploring in mature areas and exploiting old fields. The principles are especially useful in the numerous, shallow stratigraphic traps in the Jackson Group (Oligocene) in South Texas. The field example in this paper had produced oil since 1955 from wells on the updip limit of a shallow (1700 ft) barrier island sandstone reservoir. Despite the updip wells producing at a one percent oil cut, downdip wells were drilled and completed with a very commercial 25% average oil cut in 1990. Field reserves were doubled from 300,000 to 600,000 BO with the additional downdip wells. The success of drilling downdip from watered out wells can be quantified with capillary pressure and hydrodynamic flow calculations. The difference in density between oil and water is part of divisor in both equations. The difference is only 0.08 g/cc in this area, because the oil is 19 gravity (.92 g/cc) and the water is brackish (1.0 g/cc). Thus, a relatively large column of oil can be trapped downdip with only slight grain size changes. Similarly, a relatively modest, downdip water flow within the reservoir could also trap a similar sized oil column. Usingmore » reservoir conditions, each equation predicts an approximate oil column of 50 ft. Using these principles, both exploration and development geologists can find commercial oil reserves downdip from existing wells that have watered out or wells with only a hydrocarbon show and water. These principles are especially useful with low-gravity oil accumulations, heterogeneous reservoirs and downdip water flow.« less

The National Oil and Gas Assessment of undiscovered recoverable conventional oil and gas resources assigned nearly 36% of the undiscovered U.S. onshore oil resources and 28% of the commercially developable undiscovered oil resources to onshore northern Alaska. Economic screening models were applied to the geologic play assessment to estimate the commercially developable resources. This paper presents the geologic and economic assessment methodology and results; it also focuses on the robustness of estimates of the commercially developable onshore resources to changes in economic assumptions. With the economic assumptions used in the national assessment, about 60% or 6.49 billion bbl of oil of the recoverable undiscovered resources of 10.76 billion bbl of oil assessed in fields larger than 1 million bbl of oil are estimated to be commercially developable. Changes in facilities costs induced the most significant cost-related response in the commercially developable resource estimates. Price increases or cost reductions that reduce the minimum commercially developable field size to 250 million bbl from the base case size of 380 million bbl added 1 billion bbl of oil to the commercially developable resources. If, through facilities sharing or satellite-field development, the minimum commercial field size is reduced to just below 100 million bbl, estimated developable oil woul increase to 9.17 billion bbl of oil or more than 85% of the assessed recoverable oil in onshore plays.

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

The global oil system is dynamic, with fundamental parameters of volume, time, and flux rate. With certain geological assumptions, these parameters are mathematically linked by the equation, half-life = (0.693 x volume)/filling rate. Reservoired conventional oil has a well-defined half-life of 29 m.y., derived from the distribution of oil generation ages. The global oil reserve is therefore directly related to the global filling rate of reservoirs. If the global system is in equilibrium, then the reservoir filling rate cannot be less than the rate at which reservoirs seep (i.e., leak to surface). Both filling and leaking parameters are poorly constrained. Total global oil generation is estimated to be about 2.7 million bbl/yr. Surface seepage data suggest that at least 0.8 million bbl/yr of this enters reservoirs, the remainder escaping directly to surface without being trapped. This seepage rate cannot be supported under equilibrium conditions by global oil reserves of the size commonly supposed. The seepage rate implies global crude oil reserves of at least 4 trillion bbl, whereas typical current estimates based upon geological analogs are 2 trillion bbl, excluding tar sands. Either (1) the global oil system is out of equilibr um, and reservoirs are draining faster than they fill, or (2) seepage rates are lower than supposed, or (3) most seepage is due to active generation and migration straight to surface, rather than leaking reservoirs, or (4) ultimate recoverable reserves are much greater than previously thought.

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.

Crude oil from Alaska's North Slope is denuded of light hydrocarbon constituents--methane, ethane, and propane--by hydrate formation reducing the mixture-bubble-point pressure by 500 psi or more. Hydrates may have denuded completely some shallow Alaskan oil reserves in situ, making the production of this oil much more difficult.

Production of crude oil and natural gas liquids in the USSR in 1982 averaged 12.26 million b/d. Total gas production reached 17.66 tcf. About 100 new fields were discovered, but apparently none were major finds that could significantly influence production in the country. Conditions for exploration continued to worsen as exploratory drilling produced a larger share of small fields that were located in more remote areas and were characterized by less productive reservoir rocks. The major gain in oil reserves, as well as in production, was again obtained in West Siberia, although even there exploration encountered a lack of first-class prospects. The major increase in gas reserves came from northern West Siberia and from the eastern Turkmen and western Uzbek Republics. Significant exploration successes were achieved along the periphery of the North Caspian basin in the Kazakh Republic and adjoining regions of the Russian Republic. This basin may become an important producing region in the near future. Successful first finds were also made in the eastern part of the East Siberian platform, where the importance of new oil discoveries is being evaluated. At the same time, the absence of significant discoveries in most basins of the European USSR points to furthe declines in oil production in these old producing regions. In 1982, the USSR increased its efforts in offshore oil exploration. The Caspian Sea fleet of mobile rigs rose to 6 units. Three mobile rigs were ordered from Finland for exploration in the Barents Sea. Offshore exploration also continued in the Sea of Okhotsk off Sakhalin Island and in the Black Sea. Preparations were made to begin drilling in the Baltic Sea.

By 1952 the detection of hydrocarbon seeps had directed explorationists to more than 50 percent of the world's oil reserves. As the major exploration emphasis shifts offshore the detection of seeps is again a potential indicator of new reserves. Rising gas bubbles can be detected with high-resolution subbottom profilers. This means that gas seeps can be detected and pinpointed during routine seismic surveys where high-resolution profilers are used.

Mission Canyon formation oil pools in central Burke County, North Dakota, were the exploration objective for operators from 1980 to 1987. Area exploration led to the drilling of 309 tests, with successful Mission Canyon completions achieved in 134 of these wells. Spectacular initial potentials, as high as 600 BOPD, were recorded for several wells. Twenty-two Mission Canyon oil fields were discovered in the study area, all characterized by high initial potentials, rapid production decline, and subsequent stabilization at or below economic limit. Of all completion attempts, 33% were commercial ventures and 67% were economic failures. Only three Mission Canyon oil fields were total economic successes - Coteau, South Coteau, and Rival. These fields are neither the largest in well count nor aerial extent. All the producing Mission Canyon formation wells in central Burke County were studied to determine oil reserves required to reach present and historic investment hurdle rates of 25% BFIT. Several economic simulations were constructed to examine value profiles for Mission Canyon development. It was observed that profitability is associated with those wells demonstrating the greatest amount of structural relief across well-defined subsurface noses. High structural relief helped the development of favorable reservoir characteristics. Shallow Charles Formation production,more » present over many of the Mission Canyon oil fields, did not convert uneconomic Mission Canyon development into profitable ventures. The authors recommend that operators involved in central Burke County Mission Canyon exploration use structural relief across subsurface noses as the discriminating factor when selecting prospects, and that management abstain from the development of discoveries demonstrating low structural relief.« less

An experiment in three-dimensional quantitative description and computer manipulation of geologic and oil-occurrence information illustrates the versatility with which these data can be utilized. A geologic unit--for example, a sedimentary basin--is divided into discrete cells. Descriptive attributes such as lithology or oil reserves are assigned to each of the cells. A computer program selectively samples the data set for units with specified characteristics and handles the resulting subset by adding, counting, cross-tabulating, or general FORTRAN manipulation. Output may be in the form of printed maps and cross sections, quantitative description of geologic conditions, and tabulated relations between oil occurrence and various geologic parameters. Data organized in this manner can be utilized efficiently and flexibly for exploration and management purposes.

In October 1977, a significant extension to the 50,000,000 bbl Stettler D-3 and D-2 reef oil field was made 28 years after the initial 1949 discovery and 17 years after the field was considered fully delineated by exploratory and development drilling. The Stettler field is among a number of well-documented Upper Devonian reef fields and was seismically and geologically mapped before and after discovery. The potential of some Alberta reef field extensions became evident with the new oil economic reality following the Arab oil embargo of 1973. Attention was given to the structurally downdip, southwest closing rim of the Stettler dolomitized D-3 atoll during 1977-79 by the drilling of seven successful oil wells beginning with the Geneva Resources 6-17-38-20 W4 test on a prospect created by the speaker. From November 1977 to January 1, 1981, 122,869 bbl of crude were produced from the 6-17 well at an average rate of 108 bbl oil/day during that period. At least 1,000,000 additional barrels of primary Stettler oil will be produced as a result of these recent extension wells. The key to this successful prospect was the lead derived from using computer lists and decline curves of production data. By 1977, over 400,000 bbl of oil and less than 20,000 bbl of salt water had been produced from the 1960 Tenneco CPR 12-17-38-20 W4 well. This location was believed by industry in 1960 to have been close to the D-3 reef oil/water contact with an expectation of high water and low oil productivity. This example of a significant reef extension is a reminder that abundant, economic oil reserves remain to be discovered in other areas by a more realistic use of geology and production information available in existing computer files. End_of_Article - Last_Page 558

Through 1978 Wyoming had produced 4.6 billion bbl of oil and had a year-end estimated 1.8 billion bbl in known fields (includes proved reserves, NGL, future extensions, revisions, new-pool discoveries, and enhanced recovery). Production and reserves are between 3 and 4% of United States totals. Approximately 55% of past oil production has been from Paleozoic rocks, primarily Permian-Pennsylvanian, and 35% from Cretaceous sandstones. Reserves in Cretaceous rocks probably are greater than those in Paleozoic rocks, but the importance of Jurassic reservoirs is increasing. Three-fourths of past discoveries have been in structural traps, but, with the exception of the thrust belt, future discoveries will be largely in stratigraphic traps. Through 1978 Wyoming had produced 7.6 Tcf of natural gas and had an estimated 9.8 Tcf in known fields (includes proved reserves, future extensions, revisions, and new-pool discoveries). Production and reserves are between 1 and 2% of the United States totals and are concentrated in Cretaceous sandstones--Cretaceous rocks in stratigraphic traps will dominate future production. Average annual oil production during the past 20 years has been 139 million bbl. With reasonable economic incentives, future discoveries should permit production at this level to continue to the year 2000. Average annual gas production during the past 20 years has been 300 Bcf. Development of known gas accumulations and future discoveries should permit an increase End_Page 829------------------------------ in annual production to approximately 900 Bcf by 1990 and this production level should continue to the year 2000. Estimated undiscovered oil resources range from 2 (95% probability) to 8 (5% probability) billion bbl with 4 billion bbl the most likely quantity. The most promising area for future discoveries (barring bandwagon psychology!) is the thrust belt with an estimated range of 600 million to 3 billion bbl and a most likely estimate of 1.5 billion bbl. Future discoveries in the thrust belt will be in structural traps in Mesozoic and Paleozoic formations. Close behind the thrust belt in estimated undiscovered oil resources is the Powder River basin with a range of 500 million to 3 billion bbl and a most likely estimate of 1 billion bbl. Future discoveries should be in Pennsylvanian and Cretaceous rocks, in stratigraphic traps, within the central, deeper part of the basin. Other parts of Wyoming have a wide variety of possible traps and potentially productive formations. There is a long-shot chance for giant oil or gas accumulations in Permian-Pennsylvanian stratigraphic traps in the Wind River and Green River basins, similar to the Cottonwood Creek field in the Bighorn basin. These will be deep! Estimated undiscovered gas resources range from 35 (95% probability) to 100 (5% probability) Tcf with 56 Tcf the most likely quantity. Future major gas discoveries will be in Tertiary, Cretaceous, and pre-Cretaceous rocks in the Green River and Wind River basins. These basins have an average range in potential from 11 to 47 Tcf and a most likely estimate of 21 Tcf in each basin. The Wyoming portion of the thrust belt has an estimated range in potential of 8 to 20 Tcf and a most likely estimate of 12 Tcf undiscovered, but these estimates are subject to considerable change as developments continue. A significant portion of the gas potential is in "tight" sandstones that have less than 1 md permeability. Greatly increased wellhead prices and improved fracturing technology would permit ultimate gas production to be larger than the most likely estimates. End_of_Article - Last_Page 830

Many basins being explored today can be viewed as regional petroleum accumulations. The Anadarko basin is used to describe how its depositional and orogenic history, its patterns of deposition and subsequent patterns of hydrocarbon accumulation, and its basic geochemical aspects all combine to make this basin a unique regional petroleum accumulation. The explorationist must view each basin as a unique entity and fully understand its regional characteristics to efficiently compete for the petroleum reserves therein. End_of_Article - Last_Page 1499

Sixteen very large "tar" deposits are estimated to contain about 2,100 billion bbl of oil in place. This is nearly as much heavy oil as the world's total discovered recoverable oil reserves. The seven largest "tar" deposits of the world contain 98% of the world's heavy oil; that is, these seven heavy-oil deposits contain about as much oil in place as the world's 264 giant oil fields. These accumulations are remarkable not only for their size, but also for their unconventional geologic settings--in traps that feature various degrees of stratigraphic control in combination with structure; in marginal marine or nonmarine sediments; and commonly in thermally immature sediments without associated local source beds. For very large tar-sand accumulations to be formed and localized, the following are geologic prerequisites: (1) a paleodelta system comprising organic-rich source beds and very far-reaching, efficiently interfingered carrier sandstones; (2) a widespread regional cap restraining vertical fluid escape from the underlying paleodelta and channeling fluid movements laterally to the edges of the basin; (3) a homocline with updip stratigraphic convergence and, preferably, low-amplitude arching plunging into the basin; and (4) degradation of oil to heavy sour "tars" by water washing and bacterial action. Most of the settings reviewed indicate moderately rich source beds widespread over large areas, excellent gathering and focused drainage systems in paleodeltas, very long migration distance, and the predominance of regional structural and stratigraphic factors over local structural factors in determining both size and sites of accumulations. Some authors already have suggested the possibility that supergiant accumulations of medium-gravity producible oil may lie undiscovered in settings similar to the very large "tar" sands. The writer concludes that foreland basins are the most favorable areas for the possible existence of very large "tar" sand-like accumulations, but are the areas that have the highest risk for their degradation. The central parts of large rift basins are better protected against oil degradation, but gathering areas and migration distances are considerably more restricted than in foreland basins. The possibilities of passive, Atlantic-type, margin settings are unpredictable. Small intermountain basins can offer possibilities, if thick and exceptionally rich source beds are present.

In 1973 oil and gas supplied 77% of America's energy, 19% came from coal, less than 5% from nuclear, hydroelectric, and other sources. Oil and gas make up only 9% of our domestic fossil fuel reserves. Oil shale accounts for 15% and coal 74%. For a nation facing future energy shortages, this arithmetic should tell a story. Sixty-four percent of our domestic coal reserves are in the Dakotas and Rocky Mountain States. Barely 10 years ago the major oil companies first started a programmed acquisition of western coal resources for the synthetic fuel-from-coal industry. The recent dramatic changes in the price structure of U.S. fossil fuels now make synthetic gas and liquids from coal competitive with traditional supplies. Coal is not difficult to find. The geology of coal in the western basins is generally simple. Western coal's problems have been geography, economics, and politics. About 80% of western coal lies under the public domain. Indecision and politics have resulted in a three-year freeze on Federal coal leasing. This has slowed down the timetable for western coal's contribution to the national energy mix. Western coal's assets are low mining costs and low sulphur. Present resource acquisitions are almost exclusively strippable deposits. Nevertheless, only about 5% of western coal can be surface mined economically with present equipment. The real future may well lie in the development of techniques to mine clean energy from the 95% of the coal reserves which are underground. For instance, a tract of land 10 mi long and 5 mi wide in the Powder River basin of Wyoming contains more coal Btu's at a depth of 1,000-2,000 ft than all the known oil reserves in the U.S.--onshore, offshore, and the North Slope of Alaska. Herein may be the challenge and the biggest opportunities. For an End_Page 911------------------------------ energy-short nation, western coal can be the "Clean Black Ace in the Hole." End_of_Article - Last_Page 912

It is doubtful that any mature petroleum producing basin or province in the world can be classified as thoroughly evaluated. All mature basins should be carefully reappraised for their full potential. As much as 30% of the world's estimated undiscovered commercial oil and gas will come from mature producing areas. These are the exploratory "hot spots" of the past. To accelerate the finding of this potential, a high level of exploratory drilling is required. The experience gained and the earth science data collected over the years from a mature producing area afford earth scientists and petroleum engineers opportunities to expand their ideas and innovative thinking in the search for new petroleum reserves. This paper discusses various methods of reevaluating mature basins nd stresses the importance of the deliberate search for subtle traps.

Common to the Committee on Statistics of Drilling District 12 area are the recent exploration activities associated with the Central North American rift system or Mid-Continent geophysical anomaly (MGA), a major feature that runs from the Lake Superior area south into Kansas. For the last several years, much preliminary geologic and geophysical work has been undertaken, which usually proceeds a major play. The primary purpose is to test the Cambrian and Precambrian sediments know to have oil seeps in Wisconsin and Michigan. In 1984, Texaco USA drilled the first deep test, which was in Kansas. Although the well was apparently a dry hole, Texaco's findings have not been released. Kansas had a very active year with 7,451 completions, 45 more than those reported in 1983. The success rate of all wells drilled for oil or gas (7,307) was 57.5%, down slightly from 59.3% in 1983. Drilling for oil continued to predominate with 3,783 oil wells and 419 gas wells completed. Total footage was 22,486,535, up 4% from 1983. The average depth of a test drilled for oil or gas was 3,026 ft. In Missouri, the number of wells drilled for oil or gas declined 17% from 1983 levels. Most drilling continued to be in the western part of the state. A deep test in Vernon County penetrated 2,080 ft of Precambrian rocks. In Nebraska, 12 new discoveries were made in the western part of the state. Seven found new oil reserves, and 5 were tight holes; all were classified as new-field wildcats. The average depth was 5,465 ft in the 7 discoveries where the operator reported the total depth. In Mills County, Iowa, 4 wildcats were drilled to the Cambrian with depths from 3,000 to 3,300 ft. All were located approximately 35 mi north of the Tarkio field in northwestern Missouri. It is estimated that 2,000,000 ac are leased in Iowa along the MGA. In Minnesota, 400,000 ac were leased during 1984. The leases were concentrated mainly along the MGA from Duluth to the Iowa border. About 1,000 mi of Vibroseis was run across this feature. In Wisconsin, regional geophysical surveys along the MGA have been run. Companies are now doing more detailed seismic work. Acreage leased from October 1983 to January 1985 was estimated at 214,000 ac. A dry hole was drilled 1,000 ft into quartzite in Barron County.

Most petroleum geologists have wondered why the Persian (Arabian) Gulf area contained such enormous volumes of petroleum. Saudi Arabia alone has produced 44.1 billion barrels of oil, and remaining reserves are estimated at 177.2 billion bbl. Previous studies concluded the Jurassic Callovian to Oxforidan organic-rich carbonates were the only rocks considered rich enough to be the likely source for Saudi Arabia's vast reserves. These authors believed the unique size of the accumulations reflected the scale of the system, with large volumes of petroleum-generating rocks coupled efficiently to large traps. It was argued that the type of organic matter generally associated with carbonates was algal-rich, oil prone, and a more efficient generator compared with the organic matter in clastics. It was concluded that the previously identified source rocks only partly answer the question of the unique size of oil accumulations in the part of the Middle East.

Despite increasing Soviet investment in its petroleum industry, oil production in USSR declined for the first time in the post-World War II period, from 12.327 million b/d in 1983 to 11.9 million b/d in 1985. Although oil production continued to increase in West Siberia, it was not sufficient to offset declines in the old producing regions west of the Urals. In the same period, however, gas production increased sharply, from 18.9 tcf to 22.6 tcf, due mainly to development of the supergiant Urengoy field in West Siberia. Efficiency of exploration continued to decrease in all petroleum regions except offshore in the southern Caspian Sea. In all these regions, the quality of the exploration prospects worsened-smaller and less productive structures were drilled, the average d pth of drilling increased, and exploration extended into more remote areas. The main gain in oil reserves was again achieved in West Siberia, although no new fields of a size comparable to older giants in the Middle Ob region were discovered. Because of the lack of prospects in Lower Cretaceous rocks, which have been extremely prolific, exploration was essentially targeted to the deeper and less productive Jurassic and older sections. Most of the newly discovered oil fields in these sections are of small to medium size. Attempts to establish significant oil production in the northern part of the region, beneath giant gas accumulations, again failed. New, apparently large gas fields were found, but they only add to the surfeit of USSR's established gas reserves. In other petroleum basins of USSR, the best results were obtained in the southern Caspian Sea, offshore of the Azerbaijan Republic. Development and continuing exploration in the giant 28th-of-April oil field, and several other oil discoveries and gas and condensate discoveries, created a basis for steady increases in production in forthcoming years. No significant discoveries were made in other old producing regions, and exploration in the East Siberian frontier was disappointing. A promising new oil field found in the South Turgay trough may represent discovery of a completely new petroleum basin. Its petroleum potential is yet to be evaluated.

Unlike reserves of coal, iron, and copper, which are so large that apprehension of their early exhaustion is not justified, the oil reserves of the country, as the public has frequently been warned, appear adequate to supply the demand for only a limited number of years. For some years oil has been imported, and with the growth in demand, dependence on foreign oil has become steadily greater, in spite of the increase in output. Therefore, it is evident that the people of the U.S. should be informed as fully as possible as to the reserves now left in this country, for without such information the probable dependence upon foreign supplies of oil and the expanding use of which so much of modern civilization depends cannot be appraised.

Oil production continued to decline in the older fields onshore in Europe, and large-scale production from North Sea fields still awaited completion of producing facilities. Gas production increased in The Netherlands and in the British North Sea, but was near its peak from present producing fields. There were 2 giant oil discoveries in Jurassic sandstones in the northern North Sea, Statfjord in the Norwegian area and Ninian in the United Kingdom sector. A series of still mostly unevaluated oil and gas condensate fields was found in the United Kingdom sector, including 4 oil discoveries in the Moray Firth basin east of Scotland. Oil and gas fields were found in the Norwegian and Dutch areas, and a gas discovery in German waters. There was active exploratory drilling on th Atlantic shelf west of the Shetland Islands, and oil shows were reported in one well. Oil was discovered for the first time in Greece, in the northern Aegean Sea. Two wells off the coast of southern Ireland flowed oil. In Italy the Melossa field, discovered in 1973 northeast of Milan, proved to have major gas and oil reserves. An oil discovery was made on the Adriatic coast of Italy. Wells on the Swedish Island of Gotland pumped small volumes of oil from the lower Paleozoic. Minor oil and gas discoveries were made in France, and there were 4 gas finds in Germany, one of them apparently important. In the Soviet Union production of oil and condensate was 9,185,000 b/d and of gas 25.2 Bcf/d. Production from the West Siberian basin increased 40%, and most of this was from the Samotlor field. A new-pool discovery in the Jurassic of the Salym field of western Siberia proved giant-size oil reserves. Oil was found in the Paleozoic in 2 new West Siberian fields. Gas discoveries were made in central and northwestern Siberia, Middle Asia, and offshore in the eastern Caspian Sea, and new oil fields were found in the western Caspian.

Developments in California, including new discoveries and extensions of existing fields, added 253 million barrels of oil to the state's reserve, an amount which is slightly greater than consumption for this year. The success of exploration during the last 3 years has vastly improved over that for the preceding 4 years but only to the extent of discovering new oil at a rate comparable to the yearly demand.

South Texas has three natural subdivisions, pre-Eocene producing area, Eocene producing area, and post-Eocene producing area. During 1939 thirty new pools were added. Major discoveries resulted from deeper drilling on producing structures. Geological work was less than in previous years; however, several practices of value to geological work were either inaugurated or enhanced in their general use. Pressure maintenance plants for extracting optimum condensate recovery in gas fields reached an important stage of development. Oil reserves amount to 1,260 million barrels or the equivalent of 15.5 years supply. Reserves and production have increased 300 per cent and 400 per cent, respectively, since 1933.

The writer presents a revision of his papers of 1947 and 1948 so as to bring to date oil and gas developments in the U.S.S.R. and to correct and enlarge reserves estimates of land areas to 210 billion barrels, and add for offshore, principally inland sea areas 39.7 billion barrels; this compares with an earlier estimate of 150 billion barrels. The Soviet Union to the end of 1961 had extracted only 7 per cent (13.8 billion barrels) of its land reserve oil possibilities, and had developed proved oil reserves on 23.5 billion barrels, and 70.6 billion cubic feet of gas. Hence, to prove up and develop its vast reserves and deeper possibilities the expenditure by the Russian Government of vast sums of money is necessary. The ultimate reserves of land areas of the United States, we now place at 125 billion barrels of which 67.8 billion barrels have been produced; of offshore areas, mostly continental shelf, the United States has 26.3 billion barrels, production of which has barely begun. The proved United States oil reserves were 36 billion barrels at the end of 1961. L. G. Weeks places the total of United States ultimate reserves at 270 billion barrels. The second Baku (Bashkiria-Tatara-Pechora) area has been much more fully developed, and the importance of the Turkmenistan-Uzbekistan province as a major district has been proved; lists and maps of their more important fields and prospects are given. A revised map of Russian oil and gas provinces is also provided. The offshore development in the Caspian has opened three of such inland-sea offshore fields.

The enormous demands of World War II for California oil were met successfully. Production was increased from 230,263,000 barrels in 1941 to 326,555,000 barrels in 1945. This is an increase of 41.8%. The comparable figure for the balance of the United States is 18%. During the period 1941 to 1945, inclusive, California produced 18.2% of total United States oil production and 11.7% of total world production. It increased its proportion of total United States production from 16.4% in 1941 to 19.1% in 1945. One other record of past performance is of interest: California had produced to December 31, 1945, about 22% and 14% of total cumulative production from the United States and the world, respectively. This performance was accomplished by development of about 245,000 proved roductive acres, a small area compared to that in other producing states. Average ultimate recovery from California fields is estimated to be about 44,000 barrels per acre. Other major producing states have estimated ultimate recoveries of 8,000 to 14,000 barrels per acre. California pools have sufficient thickness to compensate for their restricted area extent. Despite the drain on California's oil resources by World War II, production in the middle of September, 1946, was about 870,000 barrels daily; the daily average during 1941 was about 631,000 barrels. During the period 1941 to 1945, inclusive, the discovery of new pools and new fields in California added estimated reserves equal to about one-third of production during that period. Additional reserves must be discovered in order to continue to meet the unprecedented peacetime demand for California oil. More new pools in present producing areas probably will add larger amounts to reserves than will new fields (Tidelands excepted). It will require intensified geological effort to find End_Page 2088------------------------------ these new reserves. There still is ample opportunity in California for the competent and imaginative geologist who can evolve a productive program from a mass of factual information. End_of_Article - Last_Page 2089

The year 1938 marked another twelve months' period during which the volume of newly discovered petroleum reserves in Oklahoma failed by a substantial margin to offset withdrawals. Total production of oil for the state during 1938 was approximately 170,000,000 barrels, a decrease of 23 per cent from the total for the preceding year. There were approximately 2,000 wells completed during the year, representing also a decrease of 30-35 per cent from the total well completions for 1937. The seismograph continued to be the chief exploratory method employed in the search for new structures, but there was a 20 per cent reduction in the average number of crews as compared with the preceding year. The majority of these crews were engaged in closer detail work in areas already fairly intensively explored. There was very little decrease in wildcat drilling operations. Of the 2,000 well completions 220, or 11 per cent, might be classified as exploratory wells. By far the greater number of these were located adjacent to producing pools in the central part of the state. As a result of the drilling of these 220 wildcat wells, 42 new producing areas were discovered. Of this total 16 might be considered as extensions to known pools and 26 as new pools. Thirty-nine of the discovery wells produced oil and 3 produced gas. Pennsylvanian sediments accounted for the production in 19 of the discoveries. Siluro-Devonian in 4 wells, and Ordovician in 19 wells. It is unfortunate that by far the greater number of the discoveries reveal as yet only relatively unimportant reserves. The outstanding discoveries as indicated by development to date were the Ramsey pool, in Payne County, and the Alma Oil Company extension to the St. Louis pool, in Pottawatomie County. Developments subsequent to discovery around outlying wildcats at Noble, in Cleveland County, and at Hillsdale and Waukomis, in Garfield County, have been disappointing. Drilling activities in the older pools of the state were largely routine, with the Seminole-St. Louis areas furnishing the greatest number of completions. The Oklahoma City pool continued to lead the state in output, with an annual production during 1938 of 38,796,000 barrels. The Fitts pool with 16,655,000 barrels rank d second.

Drilling activities on the basis of all wells drilling in four oil- and gas-producing states of the Rocky Mountain region increased from 687 in 1943 to 916 in 1944, an increase of 33 per cent. The total footage drilled increased from 1,442,511 to 2,245,803 feet, or 56 per cent. The number of wildcat wells drilling increased from 163 in 1943 to 171 in 1944, the increase being in Wyoming. Oil production increased, except in Wyoming, which had a decline of 985,000 barrels, the first decline since 1938. New discoveries were limited, except in Wyoming, where the number of new fields and producing zones was exceptionally high, but did not contribute much new production, pending pipe-line connections and other facilities. Geologic and geophysical work also attained a new high. I creased field developments contributed much to changes in oil reserves.

Four new oil fields to which 45,500,000 barrels of oil reserves have been assigned were discovered in California during 1939; extensions or revisions of existing fields added 257 million barrels of estimated ultimate production; total 302,500,000 barrels of new oil. The 1939 production in the state was 224,354,048 barrels. Estimated reserves were increased by 78,146,000 barrels of oil for a total of 3,178,500,000 barrels as of January 1, 1940. Of more interest to petroleum geologists than merely 1939 statistical data might be a summary of geological endeavors and results in California during the past 20 years and a prophecy for the future. Geological employment and geophysical activity from 1920 to 1939 inclusive are summarized and are correlated with results: namely, new fields discovered, producing wells completed, reserves proved, dry holes drilled, et cetera. Progress of geological thought and changing exploration methods are traced and new developments made possible by deep drilling are outlined. It is concluded that more geological man-years than in the past will be necessary to discover and develop a unit quantity of California's new future oil and gas production.

Exploration activity in Canada showed a progressive increase throughout the year. In terms of geophysical crews engaged, Western Canada was one of the most active areas in the world. The exploration effort was greater than that of 1947 and 1948 combined and was rewarded with the discovery of important new fields in Alberta where the exploration front was extended into the virgin territory of the remote northern region of the province. The greatest increase in land acquisition activity took place in Saskatchewan where almost the entire part of that part of the province, which is underlain by sedimentary rocks, was taken up by either reservation or lease. The total number of wells drilled in Western Canada amounted to 845, of which 784 were drilled in Alberta, 58 in Saskatchewan, and 3 in Manitoba. In Alberta there were 549 development wells drilled and 235 exploratory holes. Two hundred of the 235 exploratory holes were new-field wildcats, of which 13 were oil discoveries, 18 were gas discoveries, 2 were gas-condensate wells, and 167 were dry holes. The successful discovery rate in Alberta was 20.4 per cent of all exploratory wells drilled. The reflection seismograph was the most popular exploration tool used and was credited with practically all of the new discoveries. The number of geophysical crews engaged increased throughout the year. In December, which is the severest operating month of the year, 103 crews were active. Developments during 1949 increased the estimated oil reserves of Western Canada to approximately 1,100 million barrels and materially increased the gas reserves of Alberta. Daily oil production was increased to approximately 60,000 barrels per day to satisfy the demand for petroleum products in the present economic marketing area of Western Canada for Alberta crude. In order to expand the marketing area, plans were completed for the construction of a pipeline to transport crude to markets in Eastern Canada. Possibilities for the export of natural gas from Alberta were under consideration during the year. Two companies had applied for permits to export gas to the West Coast. Exploration and development activities in Eastern Canada were on approximately the same scale as in 1948, no outstanding discoveries were made, and no important additions to geological information were obtained. Two hundred and eighty-two development wells were completed, 280 in Ontario, and 2 in New Brunswick. Exploratory drilling consisted of 82 wells in Ontario, 1 in Gaspe, and 2 in New Brunswick. Five small gas pools were discovered in Ontario. The New Brunswick Oilfields Limited, and Shell Oil Company had seismic, gravity and magnetometer parties active in New Brunswick.

A large part of the Gulf Coast petroleum reserves are in transgressive sands. The history of a marine transgression is presented, and is illustrated by a discussion and by electrical-log profiles of the Cockfield (Eocene) formation. Since a transgressive sand presents conditions favorable for the migration, accumulation, and recovery of petroleum, it is advised that both local and regional studies be made of producing horizons in light of the theory of marine overlap.

In Ontario, both exploratory and development drilling decreased from 1961. Although the total number of wells drilled continued to decline for the sixth consecutive year, combined footage increased over the previous year. This reflected the increased interest shown in deeper Cambrian formations, following the discovery of the Clearville oil field. The number of offshore exploratory tests was identical to 1961, but offshore development drilling increased appreciably. The production of oil declined slightly from that of 1961 to 1,134,500 bbls. whereas natural gas production increased substantially to 15,600,000 Mcf. The minor production of both gas and oil in New Brunswick continued to decline as expected and no development drilling was carried out. In Quebec, 2 dry exploration tests, 7 development wells, and 10 structure tests were drilled, a substantial decrease from the 57 wells drilled in 1961. For the second consecutive year, there was no drilling activity in the Atlantic region. Of the 8 successful exploratory ventures in Ontario, the Clearville oil field was by far the most significant discovery. Other successes added to the oil reserves of the Gobles field and important additions to the Silurian gas fields in Lake Erie. Acreage held by Industry increased by approximately 15% in Ontario, remained static in Prince Edward Island and Newfoundland, and decreased in the other three provinces. Field activity in Eastern Canada, including both geophysical and geological parties, decreased from 31 to 22¼, party-months.

Exploration in Pennsylvania during 1963 resulted in the discovery of 3 new gas fields, 1 new gas pool, and 4 successful deeper pools. Several old gas pools and fields were extended by development drilling. Development drilling saw its biggest year in the Youngsville-Sugar Grove oil field of Warren County where 132 oil wells were drilled during the year. The daily production from this field reached a high of 1,700 b/d of crude oil. The greatest density of drilling for deep production was in northwestern Pennsylvania in Crawford and Erie Counties where operators continued development of the Medina (Lower Silurian) gas pools. The 8 discoveries are: the Artemas field, Bedford County; Mays pool, Clarion County; Sabula pool, Clearfield County; Fike field, Fayette County; Crichton and Hadden pools, Indiana County; Mt. Zion field, Somerset County; and the Sloan pool, Westmoreland County. There were 700 new wells drilled and 26 wells deepened during 1963. Of the 700 new wells, 672 were in proven fields, and 28 were exploratory tests (all deep wells). Of the 672 proven fields wells, 461 were drilled outside of underground gas storage and secondary-recovery projects, 205 wells in secondary-recovery projects, and 6 wells in gas storage. Of the 461 development wells outside secondary-recovery projects, 202 were gas wells, 198 oil wells, and 61 dry holes. The total footage drilled during the year was 1,727,051 ft. Exploratory tests totaled 28, drilling a total of 166,388 ft. of hole. Of the 28 exploratory tests, 8 were successful, and 20 were dry, giving a success ratio of 1 in 3.5. Oil pipeline runs totaled 5,014,000 bbls. of crude oil which is less than the total production of 5,238,000 bbls. for 1962. Proved oil reserves as of December 31, 1963, were estimated at 91,734,000 bbls. Gas produced totaled 92,340,000 Mcf as compared with 87,308,000 Mcf in 1962. Gas reserves were estimated at 1,214,498,000 Mcf at the end of the year. The total reservoir capacity for the storage of natural gas in Pennsylvania is 512,100,000 Mcf. Seismic crews logged 91 weeks during the year. This is an increase of about 10% over the seismic activity in 1962. No gravity work was done but geological field parties were very active.

Results of exploratory drilling in Michigan in 1946 were disappointing for the second consecutive year. Of the 259 wildcat wells drilled during the year, 26 were completed as producing wells. Twelve oil fields and 6 gas fields were discovered, 5 oil fields and 2 gas fields were extended, and a new pay zone was found in 1 field. Only one of the new fields, Brenner, Allegan County, was sufficiently developed to add appreciable new oil reserves. A second oil discovery, Stony Lake, Oceana County, completed late in November, gave indications of a promising field although at the year's end no tests other than the discovery had been developed. During 1946, 822 drilling permits were issued, an increase of 67 over 1945. Well completions totaled 823 compared with the 801 of the previous year. Forty-four per cent of the wells were productive. Average initial production of oil wells was 651 barrels per well, and average initial production of gas wells was 7,371,000 cubic feet per well. Total footage drilled was 1,705,694 feet, approximately 15 per cent less than in 1945. Wildcat footage was 608,839 feet. Oil production declined approximately 1 per cent to a 4-year low of 17,074,518 barrels. Gas production, however, showed an increase of 2 per cent for a new high of 23,774,495,000 cubic feet. Some seismograph surveys were made in the "Thumb" and east-central Michigan, but core drilling continued to be the most common method of exploration. Permits were issued for 186 geological tests, of which 60 per cent were in western Michigan. The Sun Oil Company started work on 2 secondary-recovery projects in Michigan in 1946. The Edenville oil field, Midland County, is to be water-flooded and the East Norwich oil field, Missaukee County, is to be repressured with gas.

With the search for new oil reserves extending to all corners of the earth to-day, the activities of the American Association of Petroleum Geologists are becoming more international. The continued growth in world population and the constant improvement in the standard of living place a tremendous responsibility on all exploration men to provide the necessary raw materials and resources needed. In meeting this challenge and to properly represent the growing membership of the American Association of Petroleum Geologists, a healthy evolution has been taking place in the Association. Detailed statistics have been prepared and studied for 236 or all of the major oil fields of the free world. They represent 217 billion barrels, which is 82.5% of the free world's expected ultimate. The study shows the bulk of our oil occurs: (1) on the stable side of basins, (2) in anticlines, (3) in sandstone and carbonate reservoirs, (4) from formations of Mesozoic age or younger, and (5) from a depth range of 2,000-8,000 feet. Most of the world's ultimate oil is 30° API gravity or above with mixed and asphaltic base oils predominating. The discovery of the "big" giants has been cyclic with 10-year intervals starting with the Lake Maracaibo discovery in 1917. End_of_Article - Last_Page 423

This review covers 25 reporting countries in South America and the Caribbean area. During the review year, geological and geophysical field effort was expended in search of new petroleum reserves in 16 of the 25 countries but this effort totalled only 1,298 party-months--down 25% from the preceding year. Wildcat drilling in 1961 increased 7.2% over the 1960 figure. During the year 374 exploratory wells were drilled in 14 of the reporting countries and 87 of these wildcats were completed as oil or gas producers for a success ratio of 30%. Finally, oil production for the year from the subject area totalled 1,318,610,000 bbls., up 4.2% over the preceding year. Some 80% of this total production came from Venezuela; 8 other countries--all of which have been on a producing basi for many years--provided the remainder. No new countries came on production during 1961. Substantial net acreage relinquishments of concession areas during the year by private companies are reported from Colombia, Bolivia, Venezuela, and Peru.

Among various structural forms with which oil fields may be connected, those of diapiric structure, known in many oil-bearing areas in Roumania, in the Caucasus, and elsewhere, are the least favorable for prospective drilling. They are places of mere manifestations of crude oil at the surface. Oil deposits of commercial value are found generally on different forms of structure, and may occur in more deep-seated forms, adjacent to, or otherwise associated with, diapiric forms of more superficial nature. Folds, as they occur commonly in the northwestern part of the Median zone of the Polish Carpathians, showing different stages of diapirism, are disposed en echelon, and areas intervening between such fan-like diverging folds might be favorable locations for exploration for deep-seated oil horizons in the lower part (Cretaceous) of the Flysch. This possible oil reserve has not been investigated. The longevity of Polish oil deposits depends on the primary or secondary nature of the reservoirs (whether differentiated by original process of sedimentation, or degree of subsequent cementation), on the content of gas in the reservoirs, and on the intensity of reservoir pressure. In the sub-Carpathian province, comprising the foreland depression filled with Miocene formations, only three gas fields are being exploited, and it was only in 1932 that the first test well for oil was located there; locations for two more wells have been selected on the basis of preliminary geophysical surveys. The Marginal zone of the Carpathian petroliferous province, consisting of a complex of strata in many places repeatedly superimposed one upon another as thrust slices (skiba in Polish terminology), is not promising for test drilling, with the exception of that part that has been thrust bodily, by a deep-seated thrust plane, upon the sub-Carpathian Miocene formation. At present two test wells have been commenced with the object of searching for this deep possibility, outside of the few productive areas of this type already known in Boryslaw, Rypne, Majdan, and Bitkow. In Poland there are no reserves of proved oil areas, but there exist widespread and reasonable possibilities for future discoveries. With steady progress in efficiency End_Page 1061------------------------------ and technical perfection of exploitation methods in old fields, with the inauguration of oil mining, and with general policies in the industry improving, it will be possible to lengthen the producing life of oil fields.