摘要:

Primary petroleum migration (expulsion from source rocks) remains the least understood parameter controlling the genesis of oil deposits. In spite of this lack of understanding, many petroleum geochemists (including this Author) have previously considered expulsion from organic‐rich, mature source rocks to be very efficient. This viewpoint results fromRock‐Evalanalyses of organic‐rich source rocks, analyses which demonstrate a loss of hydrocarbon (HC) generation capacity, by significant reduction inRock‐Evalhydrogen indices, as such rocks are progressively buried in sedimentary basins. However, this progressive loss of HC generation capacity is not matched by numerically‐equivalent increases either in Soxhlet‐extractable HCs or theRock‐EvalS1pyrolysis peak. Thus, we conclude that almost all generated HCs have migrated from the source rocks.Notwithstanding, the petroleum geochemistry of the Williston Basin (North America) and other considerations strongly suggest that this logic may be flawed. Instead, it appears that most generated HCs may not migrate far from their generation site, but instead are lost before source‐rock samples arrive at the laboratory for analysis. This loss occurs from a HC‐gas volume expansion, which results from the large pressure decreases in rock chips or cores during the trip up the wellbore in the course of drilling operations. The large volume expansions of these HC gases, which are cogenerated and coexist with oil in the source rocks, literally blow most generated oil in source rocks into the drilling mud during the trip uphole.If most generated HCs do in fact remain in or near their source rocks, then it can be hypothesised that source rocks must be physically disrupted before meaningful expulsion can occur. Faulting, with accompanying significant fracturing, would appear to be the optimum naturally‐occurring process for physical disruption of source rocks. If these hypotheses are valid. intensity of faulting in deeply‐buried HC “kitchens” containing mature source rocks should strongly correlate with increasing basin richness, as defined by recoverable oil divided by basin‐sediment area or volume.This possible relationship is examined in this Paper; and there is a strong correlation of increasing basin richness with increasing structural intensity over and adjacent to basin depocentres. This correlation thus supports the hypothesis that physical disruption of mature source rocks is a necessary, and previously unappreciated, controlling parameter for oil expulsion. If a relationship between physical disruption of source rocks and oil expulsion indeed exists, then significant implications would follow for:(1) basin resource assessment;(2) conventional oil exploration in frontier basins; and(3) the probable existence of very large, previously unappreciated, oil‐resource bases in f

ISSN:0141-6421    

DOI:10.1111/j.1747-5457.1994.tb00112.x

出版商:Blackwell Publishing Ltd    

年代:1994

数据来源: WILEY

摘要:

Cuba is considered here to consist of two separate geological units: afoldbelt and a neoautochthon.Thefoldbeltcan be subdivided into:(i) continental units, comprising Mesozoic Bahamian Platform and slope deposits, which are overlain by a Paleocene‐ Late Eocene foreland basin; and the Cuban SW terranes (Guaniguanico, Pinos and Escambray), which were probably originally attached to the Yucatan Platform;(ii) oceanic units, namely: the northern ophiolite belt; the Cretaceous (?Aptian‐Campanian) volcanic arc, which is overlain by a series of Latest Cretaceous — Late Eocene “piggy‐back” basins; and the Paleocene‐Middle Eocene volcanic arc which is overlain by a late‐Middle — latest Eocene “piggy‐back” basin.Theneo‐autochthonis composed of slightly‐deformed, latest Eocene to Recent sedimentary rocks, which unconformably overlie the folded belt.A large number of tectonic models for the Caribbean area have been published in recent years, but rarely include modern data on the geology of Cuba. The Author here presents a plate‐tectonic model for the western Caribbean which is based on the following premises: (i) opening of the Caribbean took place along several parallel rifts‐zones, and a main transform fault located between the entrance of the Gulf of Mexico and the Demarara Plateau; (ii) the Cretaceous Greater Antilles volcanic arc faced the ProtoCaribbean Sea, and essentially northward‐dipping subduction took place; and (Hi) the western Caribbean Paleocene‐Middle Eocene volcanic arc also faced the Caribbean Sea, with subduction dipping towards the NNW.Hydrocarbon production in Cuba comes from oilfields located in both continental and oceanic units. The Northern Oil Province coincides with the Bahamian platform and slope deposits and the Guaniguanico Terrain. The Southern Oil Province is represented by the latest Cretaceous — late Eocene sedimentary b

ISSN:0141-6421    

DOI:10.1111/j.1747-5457.1994.tb00113.x

出版商:Blackwell Publishing Ltd    

年代:1994

数据来源: WILEY

摘要:

The importance of the flow unit approach to reservoir description has been recognised recently, but its application to predict porosity, permeability and water saturation from well logs has not been attempted in previous studies. This Paper describes a genetic approach to reservoir description, which combines lithofacies analysis with discriminant analysis and probability field simulation for the identification and characterisation of flow units on the basis of core and log data.Lithofacies with distinct depositional, diagenetic and petrophysical characteristics, which essentially act as lithohydraulic flow units, have been identified from cores. A set of discriminant functions is then computed using log data from cored wells to identify lithofacies from wireline logs in uncored wells. Each lithofacies has been found by regression analysis to possess a distinct porosity and permeability relationship. The lithofacies‐specific relationships between sonic travel time and core porosity is also established by regression analysis. Porosity and permeability values predicted from regression analysis lack variability when compared to actual core data. Hence, probability field simulation is applied to add fine‐scale variation to the values predicted from regression analysis.The techniques described here can be applied to any type of reservoir. The application of these techniques has resulted in an improved prediction of porosity, permeability and water saturation for a shaly, glauconitic reservoir in the North West Shelf area of Australia, where traditional log analysis has been proved to be difficult to ap

ISSN:0141-6421    

DOI:10.1111/j.1747-5457.1994.tb00114.x

出版商:Blackwell Publishing Ltd    

年代:1994

数据来源: WILEY

摘要:

The data‐base for this study is mainly unpublished Mongolian and Former Soviet Union reports (1958 to 1989), and studies conducted by or for the Mongol Petroleum Co. (Mongol Gazryn Tos: MGT) (1989 to 1992). A very small amount of data was obtained from published literature. Until 1989, the majority of work on the petroleum geology of Mongolia either condemned the prospects, or suggested that there was only very limited oil and gas potential.However, the present evaluation, which is based on three years' work by the Author and his associates, supported by Mongol Petroleum Co. explorationists, is that three to six billion brls oil‐equivalent (o.e.) of conventional recoverable oil and gas resources within the territory of Mongolia is a reasonable expectation. The expected “most likely” oilfield size ranges from 100 to 170 million (MM) brls o.e., with the “low” oilfield size ranging from 5 to 10 MM brls o.e. and the “high” oilfield size ranging from 330 to 700 MM brls o.e.The concepts upon which these estimates are based were derived from Klemme (1980, 1983, 1986); Klemme and Ulmishek (1991); Ulmishek (1986); and Ulmishek an

ISSN:0141-6421    

DOI:10.1111/j.1747-5457.1994.tb00115.x

出版商:Blackwell Publishing Ltd    

年代:1994

数据来源: WILEY

摘要:

Drilling for Niagaran (Middle Silurian) pinnacle reefs in northern Michigan dominated the petroleum exploration scene in Michigan for 19 consecutive years (1969–1987). By the end of 1986, cumulative production from the northern reefs reached 268 MM brl (million barrels) of oil and 1.4 Tcf (trillion cubic feet) of gas. This study presents quantitative and graphic summaries of several attributes of exploration and discovery data for this period, which together provide a concise “portrait” of the exploration history of the play. Data subsequently available confirm these trends for more recent years.The success ratio of exploration wildcats peaked at 51–53% during the years 1971‐73, after a “learning period” of three years. Thereafter, it declined gradually to around 16%, which is similar to the average of the US oil industry in the last decade. The success ratio for development drilling peaked at 68% during 1971‐2, and it has fluctuated between 40 and 50 % thereafter.The frequency distribution of field sizes is log‐normal. However, since very small uneconomic or marginally‐economic prospects and fields have either not been drilled or developed, the observed distribution represents only the density distribution of economic fields.The reef fields are rather small. Reef‐substrate areas range from about 40 to about 840 acres, and recoverable reserves range from 30,000 to 22 MM brl of oil equivalent (o.e).The ten largest fields in the play were found by drilling the first 25% of the exploration wells. The discovery per wildcat peaked at 1.55 MM brls o.e. after 500 wildcats, and declined steadily thereafter to a level of 0.02 MM brls o.e. per well after 1,900 wildcats, indicating that the play had reached a state of maturity. About 25% of the discovered reserves were found in 5% of the fields, indicating a more even reserve distribution pattern than in many other plays. Consequently, the relative rate of growth of the discovered reserves has been slowe

ISSN:0141-6421    

DOI:10.1111/j.1747-5457.1994.tb00116.x

出版商:Blackwell Publishing Ltd    

年代:1994

数据来源: WILEY

摘要:

Several correlations for estimating the reservoir permeability from electric well‐log data have previously been developed. Unfortunately, none of these correlations are universally valid, since each correlation is strongly dependent on the local lithology, and the properties and distribution of reservoir fluids in the well. There is therefore a need to develop such a correlation for use in reservoir rocks of the Niger Delta Basin.Using multiple‐regression analysis, the Authors have developed empirical expressions for permeability in terms of log‐derived porosity and irreducible water‐saturation for unconsolidated sands in the Eastern Niger Delta. A comparison is made between this new expression and those previously proposed, using 218 sets of field‐measured data. Permeability estimated by the newly‐ proposed expression is found to be accurate.The expression could be valid for other oil‐producing areas, provided that the reservoir rock and fluid properties are similar to those of unconsolidated sands in the Easter

ISSN:0141-6421    

DOI:10.1111/j.1747-5457.1994.tb00117.x

出版商:Blackwell Publishing Ltd    

年代:1994

数据来源: WILEY

ISSN:0141-6421    

DOI:10.1111/j.1747-5457.1994.tb00118.x

出版商:Blackwell Publishing Ltd    

年代:1994

数据来源: WILEY

摘要:

Book reviewed in this article:“Oil and gas exploration and discoveries in China”“Tectonics and seismic sequence stratigraphy”, edited by G. D. Williams and A. Dob

ISSN:0141-6421    

DOI:10.1111/j.1747-5457.1994.tb00119.x

出版商:Blackwell Publishing Ltd    

年代:1994

数据来源: WILEY

ISSN:0141-6421    

DOI:10.1111/j.1747-5457.1994.tb00120.x

出版商:Blackwell Publishing Ltd    

年代:1994

数据来源: WILEY

ISSN:0141-6421    

DOI:10.1111/j.1747-5457.1994.tb00121.x

出版商:Blackwell Publishing Ltd    

年代:1994

数据来源: WILEY