Km Of Seismic Lines Research Articles

Hungarian Exploration Potential

In the Pannonian basin from the Pliocene Formation, commercial oil/gas production was started in 1937 by the Standard Oil of New Jersey and the National Oil Company joint venture firm (MADRT). Until now accumulated oil production was 70 million tons; for natural gas, 140 billion m{sup 3}. About 7,000 exploration, development, and production wells were drilled and 90,000 km of seismic lines were acquired. From some aspects, the Hungarian part of the Pannonian basin is a highly explored, mature area; from other aspects, it is far from that. In light of the most advanced seismic acquisitions and seismic stratigraphy, evaluation of the huge volume of organic matter-rich deltaic type Pliocene and Miocene deposits offer some new exploration possibilities. The Pannonian basin is the result of crustal extension culminating in the middle-Miocene, locally continuing with very reduced intensity until recent times. Some very deep (up to 7,000 m), medium (2,000-3,500 m), and shallow (1,000-2,000 m) subbasins were formed, where a huge volume of organic matter-rich sediments has been deposited. The Paleogene and Miocene subbasins are related to wrench-fault movements, while the Pliocene subbasins are related to wrench-fault movements, while the Pliocene subbasins are real postrift basins. There are different types ofmore » structures/forms for the hydrocarbon accumulations: classical anticlines, deposited arches above the Mesozoic-Paleozoic basement highs, overthrust zones, and flower structures. New explorations targets are expected in the thick Mesozoic dolomite and limestone formations, too.« less

Miocene-Pliocene paleogeographic evolution of a tract of Sarawak offshore between Bintulu and Miri

A data base consisting of5,200 km of seismic lines and data from six wells has been utilized to recontruct the evolution of the main environments of sedimentation in a tract of the Sarawak Offshore between Bintulu and Miri. A sequence of six maps shows the progressive shifting through time of the position of the paleo-coastline in the area as well as that of the major deltaic systems. The presence of a morphological paleoescarpment along the so-called West Baram line is evident since at least the Middle Miocene. The data suggest its presence also in older ages but it cannot definitely be demonstrated with our data set. The basin to the northeast of this paleoescarpment has been filled mainly during the Late Miocene-Pliocene by the deposits associated with the progradation of the paleo­ Baram delta system. The spatial distribution of the different environments of sedimentation is at any time controlled by the position of the coastline (input of sediments) and by the presence of the paleoescarpment. This situation is still reflected by the present geography of the area.

EXPLORATION AND EVALUATION OF THE ZUATA AREA, ORINOCO OIL BELT, VENEZUELA

Exploration activity in the Zuata area within the Orinoco Oil Belt in Venezuela has included the drilling of 161 wells and the recording of 3,000 km of seismic lines. Based on these results, a productive area of 9,200 sq. km has been defined, containing 79.3 B cu.m. (499 B brl)† of crude oil in‐place, with densities ranging from 1.021 to 0.934 g/cu.cm (7–20 °API).The principal productive sands are of the Tertiary Officina Formation, deposited during a transgression which occurred in the Miocene. A distinctive feature of the productive formation is its progressive onlap against older rocks (Cretaceous, Paleozoic or Pre‐Cambrian) in a southerly direction which, together with overlying shales, provide the trapping mechanism for the oil which migrated from the north. The productive sands were deposited in a fluvial to coastal plain with deltaic developments. The sands are unconsolidated and fine‐ to very coarse‐grained, with an average porosity of 34% and a permeability of 7μm2(7D). The structure is a monocline dipping 0.5° to 2° to the NE, and the trapping mechanism is principally stratigraphic. In the 134 producers, 300 tests were completed which resulted in an average production of 25 cu.m/d (160 b/d) per well by beam pumping without dilution or heat. Subsequently, a steam cycle of 5,000 metric tons was injected into 16 wells; production increased to some 200 cu.m/d (1,250 b/d) per well.For future development, a Priority Area has been selected: this Area covers 3,500 sq kin, and contains 40.5 B cu.m (255 B brl) of crude oil with a density range of 1.014 to 0.993 g/cu.cm (8–11°API). The oil is at an average depth of 610 m, and the average net oil‐sand thickness is 60 m. The oil‐sand is generally divided into three zones separated by shales, and the gross productive thickness is some 110 m.Similar to Maraven ‘s experience in the oilfields of the Bolivar Coast in Western Venezuela, it may be expected that reservoir compaction will occur, and will be efficiently activated by steam‐soak or “huff and puff’. Based on core compressibility measurements, a recovery factor from compaction drive and solution gas treatments could reach 12 % of the oil in‐place. Under this premise, the Priority Area could have a potential recovery of 4.9 B cu. m. (30.6 B brl), which could support a production of 160,000 cu.m/d(1MM b/d) for 100 years. Any follow‐up steam drive can be assumed to recover at least an additional 10% of the oil in‐place.A Conceptual Development Plan based on clusters, inclined wells (due to the shallow depth) and steam soak has been proposed, and will be validated by a pilot test consisting of a seven‐well cluster.

THE ORINOCO OIL BELT, VENEZUELA

The Orinoco Oil Belt of Venezuela is a very extensive, non‐discrete, crude‐oil producing area located along the southern third of the Maturín (Eastern Venezuela) basin, north of the Orinoco River and the Guayana Shield. It extends due westwards from Puerto Ordaz for 460km; the main producing areas, defined on the basis of productivity and magnitude of crude oil in‐place, cover 13, 600 sq. km. There are no significant surface indications of petroleum anywhere in the Belt. The first well drilled was La Canoa‐1 in 1936, initiating a stage of exploration which ended in 1967 with publication of a preliminary evaluation of the potential reserves; the Ministry of Energy and Mines, then of Mines and Hydrocarbons, and the State oil company Corporación Venezolana del Petróleo (CVP) completed a second stage of exploration in 1977; Petróleos de Venezuela and its operating companies then drilled 669 wells in five years (1979–83) totalling 643,000 m with 5.5 MM** m of logs, and shot 15,000 km of seismic lines at a cost of $US 615 MM, an effort conservatively estimated as having taken 2,500 man‐years. The main producing areas are, from east to west, Cerro Negro, Pao, Hamaca, San Diego, Zuata, and Machete. Petroleum characterisation in the Belt is based on the study and analysis of 288 samples. Viscosity (dynamic) of the crude oils at reservoir conditions ranges from 2,000 to 7,000 m Pa.s (cp)†.Production rates average 25 cu. m/d(160 b/d), increasing fourfold after steam stimulation. At the end of 1985, production was 13,000 cu.m/d(80,000b/d)†, from the Cerro Negro and Hamaca main producing areas. Operating costs are similar to those in other heavy‐crude oilfields in the basin. The volume of crude oil in‐place is estimated to be 187.8 B cu. m (1,181 B brls), which makes the Orinoco Oil Belt the largest crude oil accumulation in the world. Proved reserves are 4.161 B cu. m (26.170 B brls). and unproved reserves 14.822 B cu. m (93.230 B brls). Investigative activities are underway, particularly in the Cerro Negro and San Diego producing areas. In subsequent papers of this thematic survey, A. Isea presents a geological synthesis of the Orinoco Oil Belt; G. Don Kiser discusses the exploration results of the Machete area; A. Santos and L. Frontado describes the reservoir geology of the Cerro Negro steam‐injection area; and A. Vega and I. de Rojas summarise exploration results from the Zuata area.

Geological studies as a risk-reducing factor in exploration ventures with special references to the South China Sea

During 1981 and 1982, 40 new exploration wells had been drilled and 10,000 km of seismic lines had been recorded in the Indonesian East and West Natuna basins. New geologic syntheses were developed and have led to new discoveries. During the last 15 years these activities were supported by cumulative expenditures amounting to nearly U.S.$.5 billion. However, more investments will be required for further development. With the present economic situation and the geological risks involved, such massive capital investments need careful handling from both the host country and investors. It is therefore desirable that risks involving future investments be reduced as much as possible. Being a host country, Indonesia intends to maintain a healthy investment climate for foreign investments. During the last 15 years the Indonesian petroleum industry has offered various incentives to meet investor demands for less risk on returns. Another risk-reducing device is being introduced to deal with geological uncertainties inherent in exploration decisions. The approach has been designed to encourage a wide range of possibilities, from limited studies of regional geology, economics, and engineering to in-depth study of petroleum geochemistry and source rocks. Since decisions on exploration ventures involve knowledge of basin geology, joint studies may reduce investment risks in the basin and therefore can be regarded as an investment incentive. Because of its unique geology, the Natuna basins area can be used as a model.

Oil and Gas Developments in New Zealand and Southwest Pacific Islands in 1981

New Zealand has experienced a strong increase in exploration activity. Offshore license holdings are up to 164,015 km2, an increase of 53%. Onshore licences are 20,467 km2, an increase of 77%. Four offshore wells were drilled to a total depth of 13,690 m; they were all dry. Onshore drilling amounted to 8,548 m and was concentrated around last year's oil discovery of McKee-2A. The field was confirmed by 1 extension well, McKee-3A, whereas 2 other wells were dry and a fourth extension well still drilling by year end. Onland seismic surveys covered 484 line-km, while marine seismic work amounted to 6,561 km. Because of increased re-injection of gas in the Kapuni field, the saleable production slightly went down, but condensate production rose by nearly 50,000 m3, i.e., 21% more than last year. With the strongly increased output from the offshore Maui field, total gas production for sale was 1,286 × 106 m3, up 20.2%, while the total production of condensate was 550,101 m3, up 31.3%. LPG production rose to 41,179 m3, up 50.8%. Tonga has experienced a virtual standstill in exploration, but CCOP/SOPAC has completed and prepared for publication its interpretation of a single-channel seismic survey over the southern Tongan platform, conducted the year before. In Fiji, license areas remained unchanged but a new company, Bennett Petroleum Corp., acquired a 75% interest in Block D. Extensive geochemical sampling and minor geophysical surveys were undertaken in several blocks, and a shallow stratigraphic hole was drilled to 307 m. In Vanuatu, which still lacks petroleum legislation, no exploration licenses were granted. A CCOP/SOPAC-sponsored study of all existing marine seismic surveys has been completed, and a summary of results has been prepared for publication. The Solomon Islands, too, has no petroleum legislation as yet. CCOP/SOPAC ran single-channel seismic surveys to a total of 1,115 line-km, mainly near Rennell Island but also some in the Central Solomons Trough. In Papua New Guinea, the total concession areas increased to 72,600 km2. Oil companies recorded 550 km of seismic lines onshore, and 1,716 km offshore; aeromagnetic surveys covered 9,779 line-km. Outside concession areas, CCOP/SOPAC conducted single-channel seismic surveys in the New Ireland basin between Bougainville and Manus Island, for a total length of 4,964 km. Interpretation of these surveys has been completed and prepared for publication. An appraisal well, Barikewa-2, was spudded shortly before year-end; initial reserve estimates for this large anticline had run as high as 10 tcf of gas in place. Drilling depth will be about 2,120 m.

COCORP southern Appalachian data

The data packages for 348 km of seismic lines in the Georgia‐Tennessee area of the southern Appalachian region are now available for the cost of reproduction and shipping. These data were obtained by the Consortium for Continental Reflection Profiling (COCORP) are applying sophisticated continuous seismic reflection techniques to the solution of geologic problems of the earth’s crust and upper mantle. The operation is part of the U.S. Geodynamics Project sponsored by the National Academy of Sciences and funded by the National Science Foundation. The executive committee of the consortium consists of members from Cornell University, University of Houston, Princeton University, University of Texas at Austin, University of Wisconsin, and Shell Oil Co. Cornell University has the operational responsibility.

Southern Appalachian data now available

Data packages obtained by the Consortium for Continental Reflection Profiling (Cocorp) for 348 km of seismic lines in the Georgia‐Tennessee area of the southern Appalachian region are now available. The packages consist of the following:1. Basic display package of 28 prints for $90, consisting of location maps, isovelocity plots, and CDP stacked prints of six lines at each of two scales: (a) horizontally 5.6 cm = 3 km, and vertically 5.6 cm = 1 second of two‐way travel time; (b) horizontally 2.8 cm = 3 km, and vertically 2.8 cm = 1 second of two‐way travel time.