Structural Nose Research Articles

Seismic Amplitude Variations and Detection of Sand Bodies: ABSTRACT

An area offshore Louisiana with an abundance of well control and seismic data provides an opportunity to verify the presence of interpreted sand bodies. In gross aspect the seismic sections show two major zones: one with highly discontinuous reflections of modest amplitude and a deeper zone with continuous parallel reflectors of low amplitude. The latter is due to an overpressured shale section interrupted by poorly developed sands and hard streaks, while the former is dominated by laterally discontinuous blocky sands which can be readily mapped from seismic events. Looking at the sands in more detail, the reflectors are actually continuous, following time-lines, but the amplitudes diminish where the sands terminate. Thus, reflector amplitudes can be used to determine the distribution of sand bodies of the order of 70 to 100 ft thick. In one area a sand body can be mapped across a structural nose, delineating a structural/stratigraphic trap, and elsewhere the presence of gas is distinguishable from lithologic changes by the intensity and character of the associated seismic signature. One-dimensional modeling indicates that seismic response to the sand depends principally on density contrast with the shales. Two-dimensional modeling based on well log parameters and seismically derived geometries suggests that the sand bodies may be due to localized deposition and have been enhanced by differential compaction. End_of_Article - Last_Page 980------------

Geology and Geophysics of Middle Mississippian (Valmeyeran), Ewing Area, Jefferson and Franklin Counties, Illinois: ABSTRACT

Since 1976, significant new oil reserves have been discovered in the Ewing area of Jefferson and Franklin Counties, Illinois. One new field and three deeper pool discoveries contain oil reserves in excess of 1.2 million bbl. These oil reserves are in Middle Mississippian limestone at depths of less than 4,000 ft (1,219 m). Spring Garden field, discovered in November 1977, was drilled on a seismic prospect and has 600 acres (240 ha.) under production from the McClosky Limestone Member of the Ste. Genevieve formation. A study of a core from the field indicates the reservoir was deposited in an oolite bar or beach environment similar to present-day deposition at the Lily Bank oolitic shoal in the Bahamas. The trap at Spring Garden field is formed by the updip pinch-out of porous oolitic limestone into a tight micritic lime mud on a structural nose. The field has primary recoverable reserves of 600,000 bbl of oil. Based on seismic work and well control, deep tests were drilled in three old fields: Bessie, Ewing East, and End_Page 1281------------------------------ Taylor Hill. All three fields had previously produced oil from the O'Hara Limestone Member of the Ste. Genevieve formation. New production has been established in the three fields from the deeper Salem and Warsaw limestone section. Oil in all three fields is found in a combination of structural and stratigraphic traps. New reserves in Ewing East and Taylor Hill total about 400,000 bbl of oil. The Bessie field is currently in the development stage but preliminary indications show the reserves should greatly exceed those of Taylor Hill and Ewing East. Recent geophysical work in the Ewing area, employing a portable mini-hole seismic crew, indicates several more untested features which occur along the same Middle Mississippian depositional trend that created the producing facies in the above fields. The new portable mini-hole seismic operation has made it possible to survey areas previously unaccessible by deep hole or vibroseis crews. End_of_Article - Last_Page 1282------------

Unconformities--Key to Major Oil Accumulations, North Slope, Alaska: ABSTRACT

The entrapment of oil and gas at an unconformity at Prudhoe Bay, North America's largest oil field, is well known. It now appears that other large oil and gas accumulations such as those in the Kuparuk River sandstones west of Prudhoe Bay are trapped at an unconformity. Prudhoe Bay field is on a large anticline on which the reservoir rocks have been truncated by an unconformity. The unconformity places organically rich Cretaceous shales in juxtaposition with Sadlerochit reservoir rocks. Cretaceous shales above the unconformity also provide the updip seal for the oil accumulation. Oil in the Jurassic Kuparuk River sandstones is trapped on a large structural nose by truncation of the reservoir rocks. The Cretaceous shales above the unconformity provide the seal and possibly the source for the oil. Uplift of the Barrow arch in Late Jurassic and Early Cretaceous time resulted in a regional unconformity. The truncation of older rocks by this unconformity, and the seal provided by the overlying shales are key factors to exploration of this arch which extends for more than 300 mi (483 km) along the Beaufort Sea coast. The delicate relations of source, reservoir, and trap, which are commonly controlled by one or more unconformities, are important to exploring this rich petroleum province. End_of_Article - Last_Page 684------------

Colmar-Plymouth Conundrum: ABSTRACT

End_Page 1286------------------------------The Colmar-Plymouth oil field is the only significant field found so far in the northwesternmost Illinois basin. Since its discovery in 1914, it has produced more than 5 million bbl, and still produced almost 28,000 bbl in 1977. Intermittent, but persistent search for additional production since 1914, has been largely unsuccessful. Why have no other significant discoveries been made? Does reexamination of the region considering current concepts and conditions hold any hope for additional hydrocarbon production? The reservoir at Colmar-Plymouth is the Hoing Sandstone, an isolated lens of well sorted, mature, Devonian shoreline sand. The shoreline borders the northern flank of the contemporaneous Sangamon arch. Oil in the field apparently originated in shale of the Upper Ordovician Maquoketa Group, which is exposed on the pre-Devonian unconformity beneath the reservoir. The field also lies almost on the crest of one of a series of broad northwest-trending structural noses crossing the arch. Consideration of these conditions provides our only geologic key to the Colmar-Plymouth conundrum. One legacy of the dismal and largely unguided exploration history of the past 70 years in west-central Illinois, is the accumulation of a large mass of sociologically interesting data of unpredictable scientific value. Perceptive analysis and interpretation of these data might well lead to additional discoveries and have a certain entertainment value in its own right. The shallow depth at which oil occurs in the area, the demonstrated longevity of production, and current market conditions, encourage exploration. End_of_Article - Last_Page 1287------------

Unconventional Evaluation of Cottageville Field, Devonian Shale: ABSTRACT

Recent compilation and publication of data by the U.S. Department of Energy and West Virginia University on the Devonian shale production in the Cottageville field of West Virginia have made this a good shale-study area. A preliminary study utilizing a new unconventional exploration technique has been made based on the available data. The technique is an attempt to reconstruct depositional structural conditions which are thought to control development of the natural-compaction-fracture reservoir. The depositional highs should have the coarser, less compactible material deposited whereas the depositional lows should have received the finer, more compactible materials. Minimum compaction on the depositional highs and maximum compaction in the depositional lows should result in maximum compaction fractures on the flanks of the depositional highs. Production from the shale occurs on present-day structural noses with about 250 ft (75 m) of regional dip across the field. There does not appear to be any direct relation between good producers and present-day shale structure. Most of the producers, approximately 75%, fall within a 50-ft (15 m) depositional structure interval and 100% of the producers with initial flows of over 500 MCFGD fall within the 50-ft interval. Only 11% of the Cottageville field wells had initial flows of over 500 MCFGD. This indicates the possibility of being more selective in selecting locations and substantially increasing the chances of making a good well. The high natural open flows and largest accumulated production seem to be associated with the flanks of the depositional structure. The preliminary study indicates the utilization of the unconventional technique can substantially improve Devonian shale natural-fracture-reservoir prediction, improve definition of productive limits, and demonstrate the possibility of selectively drilling tests with current economic potential. End_of_Article - Last_Page 1580------------

Geology and Current Development Activity at Little Knife Field, North Dakota: ABSTRACT

End_Page 843------------------------------Recent Gulf exploration efforts in the Williston basin have resulted in the discovery of a major new field, Little Knife, with multiple reservoir potential in a relatively untested area of the basin. The 70 producing wells drilled have been completed in the Mission Canyon Formation, but potential Devonian Duperow production has also been established in restricted areas of the field. The dominant factor in entrapment appears to be a north-plunging structural nose, though stratigraphic contribution to entrapment has not been fully evaluated. The Mission Canyon can be divided into five zones (A to E) based on lithologic and sonic log data. Zone B is the principal producing zone and was deposited in a wide variety of shore and nearshore environments. The depositional environments and diagenetic settings associated with zone B are responsible for an intricate pattern of carbonate deposition and porosity development. Little Knife, now 2 years old, has already produced 3,675,000 bbl of oil (January 1, 1979) even though during much of that time many wells capable of much higher production were restricted to 100 BOPD. Little Knife now vies for position as North Dakota's largest oil producer, as a gas treatment plant became operational in late 1978 and allowed daily field capacity to increase to approximately 15,000 BOPD. End_of_Article - Last_Page 844------------

Stratigraphic Trap Accumulation in Southwestern Kansas and Northwestern Oklahoma

An oil- and gas-bearing inlier of Morrowan sandstones presents a paradoxical situation in that water, oil, and gas are present in an inverted structural relation, some of the gas being structurally lower than oil and water. A map of the pre-Pennsylvanian topography reveals that a modified trellis drainage system was developed on subaerially exposed Mississippian strata. Southwestward-tilted resistant limestones of the Chesterian Series stood out as subparallel cuestas; intervening erosional valleys developed on interbedded nonresistant shales. Morrowan strata were deposited under conditions of cyclic marine southwest-to-northeast transgression, which was interrupted by several minor regressions. Sands were deposited during the regressive phases, and shales during transgressive phases. Small-scale structural noses and closures on the Inola limestone are largely the result of differential compaction of shales deposited over buried pre-Pennsylvanian topography. Detailed mapping affords a logical explanation for each producing well and all but a few dry holes in the Second Morrow sand of the Harper Ranch field of Clark County, Kansas. The anomalous distribution of some gas accumulation is explained by Gussow's principle, modified to apply to a stratigraphic trap.

Crude-Oil-Water Emulsions to Improve Fluid Flow in an Oil Reservoir

A field test was conducted to see if oil-in-water emulsions, prepared from petroleum crude oils, would reduce water channeling from injection to producing wells. In a two-year period after emulsion treatment of three water-injection wells, fluid production from offset wells showed increased oil recovery and lower water-oil ratios. Sweep efficiency was also improved. Introduction Channeling of injected water through high-permeability zones in heterogeneous reservoir sands results in low sweep efficiency in the displacement of crude oil. In efforts to improve the distribution of water injected into wells in waterfloods, wellbores have been treated with such solids as cement, ground limestone, and ground leather. However, even if such shallow-penetration methods do effect a better distribution of water into the formation at the wellbore, they are not likely to result in better sweep efficiency unless the higher-permeability zones are separated by shale breaks of very much lower permeability. Even shale breaks with low permeabilities may allow appreciable crossflow because the cross-formation surface areas are large compared with the formation areas at the flood fronts. A deep-penetration method should be more effective. Techniques for obtaining deeper-penetration plugging agents have been reported. These include the use of silica gel, rubber latex, and asphalt. In recent laboratory studies it was shown that oil-in-water emulsions possessed properties that suggested greater oil recovery. Injection of emulsion into sandstone cores improved sweep efficiency by improving the fluid flow heterogeneity of the sandstone cores. Field Investigation, Midway-Sunset Field, Section 5K This paper presents results obtained by injecting surface-prepared oil-in-water emulsion into water injection wells of a waterflood in progress at Section 5K of the Midway-Sunset oil field near Taft, Calif. the forming sections present briefly the geology, the waterflood results, and the results obtained by injecting 33,000 bbl of emulsified crude oil. Geological Information Fig. 1 is a structural map of the Section 5K area, contoured on top of the second finger, Top Oil sand. The structural nose dips to the southeast. A fault is shown as a heavy dashed line running just east of Wells 36, 109, and 126. Fig. 1 also shows an electric log, indicating the thicknesses and depth relationships of the producing intervals. The sands under flood are the first and second fingers of the Top Oil sands, and the Kinsey sand. Well-location hexagons indicate the wells and sands involved in the emulsion-treated and waterflooded areas. The legend gives the key to the hexagons. Note that in many wells not all sands are open. The average permeability of the first and second finger Top Oil sands and the Kinsey sand is 450 md. The sand thicknesses in both the waterflooded and the emulsion-treated areas arefirst finger, Top Oil, 10 to 20 ft;second finger, Top Oil, 10 to 11 ft; andKinsey, 6 to 12 ft. The oil gravities are about 20 degrees API for the first and second finger Top Oil sands, and the Kinsey oil gravity is 25 degrees API. JPT P. 721

Smackover Stratigraphic Traps--New Production in Old"Areas: ABSTRACT"

Stratigraphy has been recognized progressively as an important factor in the entrapment of Smackover hydrocarbons in the mature Arkansas and Louisiana producing fairway. Although most of the older fields generally were considered to be essentially in structural features, the importance of stratigraphic factors in entrapment has been dramatically focused by the discovery of Walker Creek field, Lafayette and Columbia Counties, Arkansas. The accumulation in this field is caused by stratigraphic entrapment by the updip termination of porous Smackover beds across a gentle structural nose. Discovery of Walker Creek End_Page 419------------------------------ signals the beginning of the second phase of Smackover exploration--the search for combination structural/stratigraphic and wholly stratigraphic traps--and the rebirth of exploration for large reserves in a mature segment of the trend. The regionally regressive depositional character of the Smackover in this area afforded an excellent setting for the formation of many stratigraphic traps. Porous carbonate zones, successively higher within the Smackover section, were deposited southward across the shelf. The updip terminus of each zone abuts an impermeable seal to form an ideal stratigraphic trap. The sinuous nature of the updip terminus, in many places in conjunction with low relief structural noses or closures, entraps the hydrocarbon accumulation laterally. In addition, many variations in the regional situation, due to the local depositional patterns of individual zones, tend to complicate the simple stratigraphic trap. Lithologically, the most characteristics reservoir rock is an oolitic-pelletal limestone with intergranular porosity. Porosity up to 30% is not unusual, but average porosity ranges from 10 to 20%. Various degrees of porosity destruction have resulted from the infilling of the primary porosity with sparry calcite cement. Where wave action was not sufficient to winnow out carbonate muds, no primary porosity was developed. The diverse nature of the stratigraphic traps opens up unlimited exploration opportunity on acreage once considered worthless because it was not located on closed structures. The stratigraphic phase of exploration now promises to be as profitable as was the structural phase in this old producing area. End_of_Article - Last_Page 420------------

Stratigraphy and Exploration of Lower Cretaceous Muddy Formation, Northern Powder River Basin, Wyoming and Montana: ABSTRACT

The Lower Cretaceous Muddy Formation in the Northern Powder River Basin of Wyoming and Montana was deposited during a marine transgression across a stream-dissected surface of the underlying Skull Creek Shale. The transgression occurred over most of the area, but was limited by a prograding delta on the northeast which supplied most of the sand for the area. The Muddy Formation is divided into 2 units--lower and upper. The lower Muddy was restricted to a system of dendritic channels which were incised into the Skull Creek Shale during a period of emergence. The sands were supplied from the delta on the northeast and transported south by longshore currents. They were deposited principally in a transitional marine and estuarine environment, and are comprised of fine-grained moderately sorted, partly clay-filled quartzose sands. By the time of deposition of the upper Muddy unit the incised depressions in the Skull Creek topography had been filled largely and the upper Muddy sands were deposited in a complex marine shoreline environment which resulted in offshore bars, barrier islands, beaches, and tidal deposits. End_Page 542------------------------------ Several shoreline trends are recognizable in the upper Muddy. They are progressively younger eastward and reflect the overall west to east transgression. These trends were controlled by the remnant Skull Creek topography and changing conditions of sediment supply. Production from the Muddy Formation is principally stratigraphic, however, in places structure is important in localization of accumulations. Lower Muddy production is restricted to updip channel boundaries and is localized by structural noses and updip channel reentrants. Upper Muddy production is controlled chiefly by porosity development and lateral facies changes. Exploration for Muddy sandstone reservoirs is accomplished best by the use of an isopach of the total Muddy Formation. This map shows the configuration of the Skull Creek channels and therefore the distribution of the lower Muddy sandstone bodies. It is also helpful in predicting the orientation of the upper Muddy shoreline trends where they were related to remnant Skull Creek highs and by showing an increased Muddy thickness due to sand buildups in non-channel areas. As the sand geometry is complex, abrupt stratigraphic changes are common. Electric log maps combined with zonal sandstone isopachs provide a means of visualizing these abrupt changes in sand geometry and also aid in the interpretation of depositional environments. Exploration must be focused on the location of primary stratigraphic traps which have not been altered strongly by later structural movements. The ubiquitous presence of clay-filled porosity has eliminated large areas as nonproductive. It is believed that the clay fill largely is diagenetic and occurred subsequent to primary oil accumulation. The lower percentage of clay fill in the oil-filled primary traps suggests that the presence of the oil inhibited clay diagenesis. In the last 3 years nearly 3,000 wells have been drilled in the study and search for Muddy oil. Each year new fields of significant size have been discovered. Abrupt stratigraphic changes require detailed stratigraphic work and, most important of all, courage to use the drill as an exploration tool. End_of_Article - Last_Page 543------------

Smackover's Significant Walker Creek (Arkansas): ABSTRACT

Thirty years ago, the oil industry knew all there was to know about the Smackover southern Arkansas. All production from that formation came from large anticlines that were found by seismograph--then came Creek! Now, stratigraphic traps at 11,000 ft, oolite bars trending across low relief structural noses, and porosity pinchouts bring a new frontier for the wildcatter. Leave your old ideas and your old tools behind if you join this search. Gravity and shooting are not much help. The in combination is an imaginative subsurface geologist working with an operator who is interested trend plays. When you are tracing the pattern of offshore bars along an ancestral Gulf of Mexico shoreline, it is a big country. Wherever oolites are formed, beach or bar deposits can be present, and these are the ingredients for lucrative but elusive oil fields. How many Walker Creeks will be found from Mexico to Florida? That is an interesting challenge facing the industry today. End_of_Article - Last_Page 1689------------

Smackover Trend From Mexico to Florida: ABSTRACT

The Smackover trend within the United States extends approximately 1,000 mi from South Texas to western Florida. Prolific production has been obtained from this Upper Jurassic carbonate formation in East Texas, South Arkansas, North Louisiana, and eastern Mississippi. Continuing exploration currently is extending the productive areas eastward into Alabama and western Florida and promises to extend production into South Texas. Most of the production has come from upper Smackover oolitic and pelletal limestones or their dolomitized equivalents. The three most important types of reservoir rocks are oomoldic dolomite, saccharoidal dolomite, and oolitic limestone with interoolite porosity. Reservoir porosity and permeability vary widely depending on the quality of the primary porosity, amount of secondary porosity development, and magnitude of porosity destruction. Low-relief anticlines, with up to about 400 ft of closure, are the most important structural traps in terms of present production. These closures usually are associated with Louann Salt swells which underlie the Smackover section. Fault traps, traps associated with high relief structures, and salt piercements are of lesser importance at this time, but it is anticipated that they will provide major reserves as exploration continues. Stratigraphic traps have become increasingly important exploration targets, particularly in the more mature areas where better well control adequately defines the potential trap. Major reserves already have been found in stratigraphic traps, and exploration for this trap type is rapidly increasing. Entrapment generally is provided by the updip termination of porous carbonate zones, commonly, but not necessarily, in conjunction with low relief structural noses or closures. Exploration of diverse Smackover traps has resulted in prolific production over a significant part of the trend. Continued exploration promises to extend the production into sparsely drilled areas and to discover significant new reserves even in the old producing parts of the trend. End_of_Article - Last_Page 1842------------

Mathers Ranch: ABSTRACT

The Mathers Ranch field in Hemphill County, Texas, represents another major discovery of gas reserves from the Siluro-Devonian Hunton limestone in the Anadarko basin of Oklahoma and Texas. It is the seventh significant Hunton field discovered in the deep Anadarko basin and is the result of continued exploratory drilling for Hunton and deeper objectives in the Cambro-Ordovician. Mathers Ranch field has more than 10 wells completed and the field limits are not yet defined in any direction. The discovery lies on a south-plunging structural nose transected by east-west faulting which, coupled with north dip, contributes structural entrapment. The degree to which porosity development is important as an entrapment agent is not yet defined and may be as important as structure, o even more so when the field is outlined completely by drilling. Production comes from below 17,000 ft from both intergranular and fracture porosity. End_of_Article - Last_Page 1687------------

Prudhoe Bay--Greatest Geologic Explosion of Our Time: ABSTRACT

Prudhoe Bay field, potentially the largest oil discovery on the North American continent, is on the flat-lying arctic coastal plain of Alaska. The structure of the field resulted from 2 periods of deformation. The Lisburne and Sadlerochit (Carboniferous-Triassic) productive structure is a westward-plunging anticline superimposed on a stable ancestral shelf. The anticline broadens eastward until it is progressively truncated by a major unconformity. The geologic structure is complicated by 2 fault patterns cutting rocks of pre-Cretaceous age: (1) normal, NW-SE-trending faults on the south flank, and (2) high angle stair-step faults parallel with the axial plane of the fold on the north flank. The structure of the field, contoured with the top of the Kuparuk River (Cretaceous) as datum, is a pronounced eastward-plunging structural nose. Two major depositional sequences have been recognized in northern Alaska: (1) an upper sequence composed of orogenic rocks with poor reservoir characteristics, and (2) a lower sequence ranging in age from Mississippian to Early Cretaceous which contains most of the Lisburne Group. Accumulation was controlled by structure and porosity-permeability variations. The middle and main producing zones are sandstones of Permian to Triassic age which compose a gigantic stratigraphic trap abruptly truncated and overlapped by impervious Cretaceous shales. The upper producing zones are confined to the western part of the field and consist of discontinuous lenticular sandstones of Late Jurassic and Early Cretaceous ages. A model concept of field-wide unitization will be in effect before production commences in the mid-1970s. End_of_Article - Last_Page 346------------

Lower Wolfcampian Reef in Kemnitz Field, Lea County, New Mexico

The Kemnitz field in Lea County, New Mexico, is a stratigraphic trap in early Wolfcampian (Permian) limestone. Detailed petrologic study of cores and samples from field wells suggests that entrapment is related to a shelf-margin barrier-reef which crosses a plunging structural nose. Data relative to the organic content of Holocene shelf-carbonates form the basis for material balance calculations which test the feasibility of in situ generation of hydrocarbon within the early Wolfcampian reef tract. The geologic history of the reef tract, as here interpreted, and the above calculations support the in situ theory of oil origin.

Geology and Exploration of Three Bass Strait Basins, Australia

Three major Mesozoic-Tertiary basins adjoin in east-west alignment along the eastern third of the south coast of Australia, for a distance of about 700 miles. The total area embraced by the three basins is about 100,000 square miles, and it includes part of three of Australia's six states. Three-fourths of the area is offshore shelf. The general east-west alignment of the basins resulted from sharp taphrogenic breakdown across the generally north-south Paleozoic orogenic trend of eastern Australia and Tasmania. The main faults and many of the basin features tend to have northeasterly or northwesterly trends, suggesting that rotational or transcurrent stresses were involved in the breakup and subsidence. Sedimentation began at least as early as the Late Jurassic. The Mesozoic is an estuarine to marine, poor- to well-sorted terrigenous clastic series. The Tertiary is largely marine and is more uniformly developed throughout. The lower third of the Tertiary contains extensive, generally highly porous and permeable coastal sandstone beds together with some shale and varying amounts of coal and carbonaceous beds. The middle beds consist mainly of shale. The upper third or more has a considerable amount of limestone and marl. Several unconformities are recognized. Though not all sediments bear marine fossils, the contained waters are saline beyond the limits of the rather extensive fresh-water flushing onshore. The Gippsland or eastern basin includes approximately 20,000 square miles. At least 10,000 feet of rapidly deposited Upper Jurassic-Cretaceous terrigenous clastics fills a down-faulted central trough and overlaps the basin shelves on the north and south; and about 9,000 feet of more widely extending Tertiary sandstone, shale, marl, and limestone comprises the remainder of the basin fill. The deeply silled Bass basin separates the island State of Tasmania from the mainland. It occupies an area of 35,000 square miles. The section consists of 12,000 feet or more of sandstone, shale, marl, and limestone, together with some coal, of Eocene and earlier ages. Deposition began in the central part of the basin, probably at least as early as Late Cretaceous time, and it continued throughout the Tertiary. The deposition progressively overlapped toward all flanks. The western, or Otway, basin includes an area of about 45,000 square miles. In this basin, the Mesozoic consists of sandstone, shale, siltstone, and mudstone. Deposition began during the latter part of Jurassic time and it continued, except for recognizable intervals of non-deposition, into the Paleocene. The maximum thickness exceeds 15,000 feet. A maximum of about 8,000 feet of overlapping Tertiary sandstone, shale, marl, and limestone completes the basin fill. Potential petroleum traps of the following types occur: tectonic folds; fault or fault-block structures; massive, elongate sandstone bodies associated with pronounced transgressive overlap, shale interfingering, and compaction drape; porosity abutment both above and below extensive low-angle unconformities; unconformable overlap by basin-sink sediments across broad-bottom highs and against and over major fault scarps; structural noses; extensive progressive flank overlap around a deeply silled basin by a sandstone, shale, marl, and limestone section; and porosity pinchouts. Since the mid-1920s, 130 exploratory borings have been drilled onshore in the extensively freshwater-flushed basin flanks. Numerous non-commercial oil and gas shows were logged. In 1965 and 1966, five exploratory wells were drilled offshore, up to the April, 1966, date of this paper. Three of these were located on well-defined closure in the Gippsland basin and resulted in major wet gas and oil discoveries in Eocene and Upper Cretaceous sandstone reservoirs. Prior to farmout of each of the three basins, successively from east to west, 18,000 miles of aerial magnetic and 5,320 miles of conventional seismic surveys were carried out under the direction and assistance of the writers. Comprehensive basin studies and compilations completed the preliminary investigations. Not included in the foregoing are various geophysical surveys on a much smaller scale by other companies and government agencies. Also not included are many hundreds of miles of additional shooting by the farmee preparatory to drilling.

Geology and Exploration of Three Greater Bass Strait Basins, Australia: ABSTRACT

Three major Mesozoic-Tertiary basins lie in succession along the eastern one-third of the south coast of Australia within a distance of about 700 miles. The total area embraced is approximately 100,000 square miles, and it includes parts of three of Australia's six states. Fully three-fourths of the area is classified as an offshore shelf. The general east-west alignment of the basins resulted from sharp taphrogenic breakdown across the generally north-south Paleozoic orogenic trend of eastern Australia and Tasmania. The main faults and many of the basin features have northeasterly or northwesterly trends, suggesting that rotational or transcurrent stresses and subsidence were involved in the breakup. Sedimentation began at least as early as Late Jurassic. The succeeding Mesozoic development lacks uniformity over the area, but the Tertiary is more uniformly developed throughout. Several unconformities are recognized. Though not all sediments carry marine fossils, the contained waters are saline beyond the limits of the fresh water flushing onshore. The Gippsland or eastern basin covers about 22,000 square miles. More than 12,000 feet of rapidly deposited Jurassic-Cretaceous clastic rocks fills a downfaulted central trough and overlaps the basin shelves on the north and south. About 10,000 feet of more widely extending Tertiary sandstone, shale, marl, limestone, and some coal, completes the basin fill. The deeply silled Bass basin, which separates the island State of Tasmania from the mainland, covers about 35,000 square miles. The section is composed of 12,000 feet or more of sandstone, shale, marl, limestone, and some coal. Deposition began in the central part of the basin, probably as early as Late Cretaceous time, and continued through the Tertiary, progressively overlapping radially in all directions. The western or Otway basin covers more than 40,000 square miles. The Mesozoic consists of sandstone, shale, siltstone, and mudstone. Deposition began during Late Jurassic time and continued, with laterally differing breaks in deposition, into the Paleocene; a maximum thickness of more than 15,000 feet was deposited. Approximately 8,000 feet of overlapping Tertiary sandstone, shale, marl, and limestone completes the basin fill. Potential traps for petroleum accumulation of the following types occur: tectonic folds; fault or fault-block structures; massive, elongate sandstone bodies associated with pronounced transgressive overlap and compaction drape; porosity abutment both above and below extensive low-angle unconformities; unconformable overlap of basin-sink sediments over broad bottom highs and against and over major fault scarps; structural noses; extensive progressive flank overlap around a deeply silled basin by a section composed of sandstone, shale, marl, and carbonate rocks; and porosity pinchouts. Approximately 30 exploratory wells drilled onshore in the extensively fresh-water-flushed basin flank, found numerous non-commercial oil and gas shows. The first offshore well drilled in the Gippsland basin 20 miles from the coast (the first offshore well in Australia) resulted, early in 1965, in a major wet gas discovery in thick, very porous Tertiary sandstone. End_of_Article - Last_Page 639------------

Time-Stratigraphic Analysis and Petroleum Accumulations, Patrick Draw Field, Sweetwater County, Wyoming

The search for new petroleum reserves can be implemented greatly by a more thorough understanding of why petroleum is trapped where it is. The Draw field, discovered in 1959, started a wave of exploratory effort in the Rocky Mountain area to find additional giant stratigraphic traps in the Upper Cretaceous rocks where porous and permeable sandstone pinches out on structural noses. The lack of success in finding another Patrick despite this widespread exploratory effort, means that factors not generally considered must have had a dominant influence in the accumulation. These factors are revealed only by reconstructing the geologic history of the area, beginning with the deposition of the reservoir and source rocks and tracing the structural attitude of thes rocks through time. Although several sandstone reservoirs produce petroleum at Draw, the principal productive interval consists of two sandstone bars at the top of the Almond Formation (Upper Cretaceous). The spatial dimensions, lithologic character, and stratigraphic framework of these bars suggest that they are barrier-bar sandstone bodies deposited along the margin of the Lewis sea. These porous and permeable linear barrier bars have a general north-south trend and grade updip on the west into impermeable shale and sandstone that were deposited in a swamp and lagoonal environment. A second important productive interval is approximately 40 ft. below the top of the Almond Formation. The areal distribution, lithologic character, and stratigraphic framework of sandstone in this interval suggest th t it was deposited as a tidal delta in a lagoon. Each of the three main productive sandstone bodies has a different oil-water contact. The geologic history of the Draw area shows that, by the beginning of deposition of the Lance Formation (Upper Cretaceous), conditions were favorable for petroleum accumulation. The reservoir sandstone beds had 1,200 ft. of overburden which had accumulated in the several million years since the reservoir sandstone beds were deposited. An early trap was formed where these sandstone beds were warped over an east-plunging structural nose, and early migration of petroleum produced a large accumulation a few miles south of the present field. When the present Wamsutter arch came into existence in post-early Eocene time, the old trap was opened and the accumulation spilled northward to be trapped at the present location of the Draw field. The search for more Patrick Draws must include more than an analysis of present structure and potential reservoir rock. The time of formation of the trap, structural modification of the trap through time, and associated origin and migration problems are hidden factors that play the dominant roles in the formation of a large petroleum accumulation. Exploration geologists must learn more about the regional framework of sedimentation--the cause and effect of incipient structural development in depositional areas. They must understand how these factors relate to the geologic history of a region.

Sleepy Hollow Field of Red Willow County, Nebraska: ABSTRACT

The Sleepy Hollow field, on the southwest flank of the Cambridge arch, is a recently discovered oil field of major importance which produces from multiple pay zones at a relatively shallow depth. The oil accumulation is partly controlled by a structural nose, trending south-southwest across the field. A large area of limited reversal may be mapped near the center of the field. Good porosities across the southern half of the field are responsible for production from the Lansing-Kansas City limestones. The principal producing limestone of this group is the C zone. The build-up of porosity in the C zone is a part of a porosity trend which can be traced for a considerable distance east and west of the field. Production from the basal sand is controlled by an oil-water contact on the flanks of the structure and by a pinch-out or truncation of the sand at the northeast end of the field. Cumulative production from the Sleepy Hollow field exceeds 10 million barrels. The Lansing-Kansas City has contributed approximately 3 million barrels and the basal sand has produced approximately 7 million barrels. The wells in the field average 3,500 feet in depth and can be completed for less than $40,000. End_of_Article - Last_Page 116------------

Patrick Draw Field, Sweetwater County, Wyoming--An Old Stratigraphic Trap: ABSTRACT

The search for new petroleum reserves can be greatly implemented by a more thorough understanding of why petroleum is trapped where it is. The Draw field, discovered in 1959, started a wave of exploration effort in the Rocky Mountains area to find additional giant stratigraphic traps in the Upper Cretaceous rocks where porous and permeable sandstones pinch out on structural noses. The failure to find another End_Page 1574------------------------------ Draw, despite a widespread exploration effort, signifies that factors not generally considered must have had a dominant influence in the accumulation. These factors are revealed only by examining the geologic history of the area, beginning with the deposition of the reservoir and source rocks and studying the structural attitude of these rocks through time. Although several sandstones are petroleum-productive at Draw, the principal producing zone consists of two sandstone bars at the top of the Almond Formation (Upper Cretaceous). The spatial dimensions, lithologic characteristics, and stratigraphic framework of these bars suggest that they are barrier bar sandstones deposited along the margin of the Lewis sea. These porous and permeable linear barrier bars have a general north-south trend and, updip to the west, grade into impermeable shale and sandstone that were deposited in a swamp and lagoonal environment. A second important productive zone occurs approximately 40 ft. below the top of the Almond Formation. The areal distribution, lithologic nature, and stratigraphic framework of sandstones in this zone suggest that they were deposited as parts of a tidal delta in a lagoon. Each of the three main productive sandstones has a different oil-water contact. The geologic history of the Draw area shows that, by the beginning of the time of deposition of the Lance Formation (Upper Cretaceous), conditions were favorable for petroleum accumulation. The reservoir sandstones had 1,200 ft. of overburden and several million years had elapsed since the reservoir sandstones were deposited. An early trap was formed where these sandstones were warped over an east-plunging structural nose, and early migration of petroleum produced a large accumulation a few miles south of the present field. When the present Wamsutter arch came into existence in post-early Eocene time, the first trap was opened and the accumulation spilled northward to be trapped at the present location of Draw field. The search for more Patrick Draws must include more than an analysis of present structure and potential reservoir rock. The time of formation of the trap, the structural modification of the trap through time, and the associated origin and migration problems are hidden factors that play the dominate role in formation of a large petroleum accumulation. Exploration geologists must know more about the regional framework of sedimentation and the cause and effect of incipient structural development in depositional areas, and understand how these factors relate to the geologic history of a region. End_of_Article - Last_Page 1575------------