Commercial Discoveries Research Articles

A REVIEW OF HYDROCARBON HABITATS IN BANGLADESH

Bangladesh, with approximately 25 trillion cubic feet (TCF) of gas initially in place and 15.52 TCF of initial recoverable reserves, and an average success ratio of 3:1, has emerged as a new hydrocarbon exploration frontier. The country occupies the major part of the Bengal Basin and is essentially located in a convergent‐margin basin that owes its origin to the Early Cretaceous rifting of the Indian Plate away from Antarctica, the formation of the Indian Ocean (part of Palaeo‐Tethys), and ultimately the collision of the Indian Plate with the Eurasian Plate. The Bengal Basin is filled with approximately 20km of mostly Tertiary siliciclastic sediments comprising a spectrum of facies including deep‐ to shallow‐marine, deltaic and fluvial types. The presence of thick sequences of reservoir‐quality sandstones coupled with organic‐rich shales, and of different kinds of traps including broad anticlinal structures, makes the basin highly prospective for hydrocarbon exploration. Of the exploration wells (52 onshore; 12 offshore) so far drilled in Bangladesh, a total of 22 reported commercial discoveries of natural gas from sandstones in the Miocene‐Pliocene Surma Group. The hydrocarbon potential of older sequences, especially the Eocene Sylhet Limestone and the Oligocene Barail Group, are not adequately known at present. However, initial indications (e.g. the presence of suitable source rocks, high‐pressure zones, “dim” and “flat” spots and velocity sag in reef complexes in the Sylhet Limestone) tend to favour the hydrocarbon prospectivity of these sequences.

TECHNOLOGY, TEAMWORK, RESPECT AND PERSISTENCE: INGREDIENTS OF SUCCESSFUL EXPLORATION IN THE ONSHORE OTWAY BASIN

Origin Energy Resources Limited has been an active explorer of the onshore Otway Basin in southeastern Australia for over a decade. Since 1989, the company has acquired 1,893 km and 358 sq km of 2D and 3D seismic data respectively, and participated in the drilling of 21 exploration and appraisal wells, 18 of which it operated, at a net cost of over $25 million.The primary exploration targets have been fluvial sandstones developed axially in a series of elongate half grabens that formed in initial response to the separation of the continents of Australia and Antarctica in the Late Jurassic to Early Cretaceous. The most significant of these depocentres, in terms of established hydrocarbon potential, is the highly faulted, NW–SE trending Penola Trough where these reservoirs are informally referred to as the Sawpit Sandstone and the Pretty Hill Sandstone.As the company’s geological understanding of the Penola Trough improved over time, so its exploration efforts were rewarded with new commercial discoveries at Haselgrove, Haselgrove South and Redman, and through successful appraisal of Ladbroke Grove. With respect to the application of advanced technology, 2D and 3D seismic are now subjected to Prestack Depth Migration to improve imaging of the subsurface, and Amplitude Versus Offset, Seismic Variance, Seismic Attribute, Fault Analysis and 3D Visualisation processing and/or software are also used in an integrated manner to facilitate interpretation of these data sets. Nuclear magnetic resonance logs are run in most wells to characterise gas-bearing reservoirs.Technology, respect and persistence have all played key roles in optimising the exploration process. So too have corporate teamwork and collaborative research with representatives from academic institutions and government agencies, and with industry consultants and contractors. The complex interplay between many of these success factors is illustrated by way of a case history, specifically that of the discovery and commercialisation of a low quality gas resource at Ladbroke Grove.In the fullness of time, the company is confident that further exploration success in the onshore Otway Basin will see new market opportunities addressed in terms of both gas and electricity supply. It is also hopeful that oil will eventually be found in commercial quantities.

ABSTRACT: Developing an Exploration Tool in a Mature Trend: a 3D AVO Case Study in South Texas

Summary Successful exploration for new reservoirs in mature trends often requires trying techniques unproven in the area. The Vicksburg Formation in South Texas has been heavily explored using subsurface geology and structural mapping based on conventional seismic data. Although there is a scarcity of direct hydrocarbon indicators such as bright spots, models generated using dipole sonic data suggested that Class 2 AVO anomalies would be associated with gas reservoirs. A pilot reprocessing study demonstrated that gas reservoirs generate Class 2 AVO anomalies and that incident angles greater than about 26o are required to observe them. A large non-exclusive 3D survey was reprocessed using non-hyperbolic moveout and resulting angle stacks were analyzed. Several untested anomalies were identified, including stratigraphic traps. Wildcat drilling based on this effort has resulted in six commercial discoveries and two dry holes, a success rate significantly higher than was achieved through conventional subsurface geology and structural mapping.

2000 EXPLORATION REVIEW

The level of exploration and appraisal activity in 2000 maintained a level similar to that of the previous year. Drilling activity offshore increased slightly from 1999, maintaining the gradual increase from a low in 1991.Onshore drilling activity also increased slightly, but is still markedly down on expected levels; new permits are not being awarded due to native title issues. Onshore and offshore basins showed a continuing decline in 2D seismic acquisition, but a continuing increase in 3D acquisition. The gradual increase in drilling activity over the past 10 years is, in part, attributed to increased density of drilling in areas that have had 3D seismic coverage.The offshore activity continues to be focussed in the Carnarvon Basin, in which 73% of the wells were located, including perhaps the most significant discovery, Laverda –1, drilled by Woodside. A campaign of 25 wells by the Apache-led JV resulted in three potentially commercial discoveries: Corvus–1, Linda–1 and Tanami–4 (renamed the Simpson field).Overall success rates were high, but this is not translating to commercial reserve additions because of the number of sub-economic oil accumulations and a predominance of gas rather than oil.Onshore a further round of acreage was released in the Cooper/Eromanga Basin, and a surge of activity is expected over the next two to three years. However, award of blocks is being held up by delays in approvals related to native title, which is a major issue for the onshore industry.The new EPBC Act has created significant uncertainty in the industry, with respect to how it is being implemented. It has already led to significant delays in operations and therefore execution of committed work programs.

1998 EXPLORATION REVIEW—GEOLOGICAL SIGNIFICANCE OF NEW DISCOVERIES AND DEVELOPMENTS

A record level of offshore exploration activity was achieved during 1998, despite a significant fall in the oil price. Seventyfour offshore wells were drilled, far exceeding the previous record of 64 wells achieved in 1990. Conversely, only 94 onshore exploration wells were drilled during the year, 25 fewer than in 1997, resulting in a slight reduction in the total exploration wells drilled from 176 in 1997 to 168 in 1998, following what had been a steady increase since 1992. Seismic acquisition in 1998 was also at a record level, twice that recorded in 1997. In contrast, the final quarter of 1998 may reflect the reduced activity forecast by industry, with less exploration wells spudded and almost 10,000 line-km fewer than that shot during the 1997 December quarter.This increased offshore exploration activity was rewarded with several discoveries and appraisal successes. The Carnarvon Basin was again the most successful area for offshore exploration in 1998, with 35 wells spudded during the year. The discoveries included Gipsy–1, Rose–1, Lee–1, John Brookes–1, Vincent–1, Caribou–1, Legendre South–1 and Mutineer–IB. In addition, significant successful appraisal drilling included two Gorgon wells, Egret–2, Dockrell–2 and Woollybutt–2A ST1.The Cooper/Eromanga Basin continued to be the focus of onshore exploration in Australia. Fifty-two exploration wells were spudded during the year. Discoveries were heavily weighted toward gas, with only one oil discovery in the basin, Chilla–1. The most significant gas discoveries included Verona–1 and Cabernet–1.Other important oil and gas discoveries and appraisal successes occurred in the Bonaparte Basin, at Sunset West–1, Sunrise–2 and Evans Shoal–2; in the Browse Basin, at Caspar–IA and two of the Cornea wells; in the Otway Basin, at Killanoola–l/DWl; in the Bass Basin, at White Ibis–1; in the Bowen Basin, at Yandina–2; and in the Surat Basin, at Digger–1 and West Noorindoo–1. Three significant appraisal wells were drilled in Papua New Guinea during 1998: Hides–4 proved continuity of the Hides Field over a distance of 12.6 km, Moran–4X extended the Moran Field to the northwest and Moran- 5X constrained the southeastern extent of the field. There were also significant discoveries in two New Zealand basins and these are covered in greater detail in Plume (1999).The lower oil price presents a challenge for the industry to maintain these high levels of exploration activity. New technology and better data quality have allowed re- interpretation of previously uneconomic or sub- commercial discoveries to successfully confirm the existence of economic fields. Several of the recent commercial discoveries followed up uncommercial discoveries drilled as much as 30 years earlier and have highlighted the fact that potential still exists in these areas. Improved subsurface imaging through 3D seismic acquisition, high-resolution processing, pre-stack depth migration and advanced time-to-depth conversion together with improved geological understanding has contributed to many of the successful wells drilled in 1998.

The Paleocene deepwater sandstone play West of Shetland

Following the discovery of oil in Paleocene sandstones in the Foinaven and Schiehallion fields in 1992 and 1993, exploration in the Faeroe–Shetland Basin has been very active. Most of the basin has been covered with 3D seismic surveys and numerous wells have been drilled for the Paleocene deep water play. However, success in terms of commercial discoveries has been limited. Detailed analysis suggests that the Foinaven/Schiehallion geological setting is unique in terms of hydrocarbon charge history, reservoir quality and trapping style. Oil charge is attributed to the presence of a Mesozoic high (Westray Ridge), which both focused charge and retained oil prior to remigration into Paleocene traps. The T35–T36 sequence which includes the Andrew Tuff appears to provide an effective top seal across the basin and all significant discoveries have been made in the T31–T35 fairway directly underlying it. Although reservoir sandstones similar to those found in the Foinaven and Schiehallion area have been encountered across the entire Faeroe–Shetland Basin, their relatively shallow burial depth and their position at the base of slope at Foinaven and Schiehallion appears to be unique in the basin. Several gas discoveries have been made in the Flett Sub-basin, located to the northeast of the Foinaven/Schiehallion area. The Flett Sub-basin has all the ingredients of a successful Paleocene hydrocarbon play, such as pervasive charge, an effective regional top seal, and stacks of Lower Paleocene deep-water sandstones and shales. However, trap definition is difficult: most remaining structures rely on a stratigraphic trapping component. The definition of top reservoir sand on seismic data is not straightforward, as seismic imaging techniques, including direct hydrocarbon indicator (DHI) analysis, are often ambiguous. T31–T35 sandstones in the deep Flett Sub-basin tend to be tight, although a considerable number have been found to have good reservoir properties. Prediction of areas where reservoir quality is preserved will be a main challenge for continuing exploration in the deep part of the Faeroe–Shetland Basin, including the undesignated area adjacent to Quadrant 204.

The petroleum systems of the Pechora Platform Foreland, Russia

The Timan-Pechora hydrocarbon basin is one of the most petroliferous provinces of Russia. It is at a mature stage of exploration onshore but is still poorly explored offshore. The exploration within the offshore extension of the Pechora Platform commenced in 1988 and has resulted in five commercial discoveries of oil and gas/condensate, the Severo-Gulyaevskoye, Pomorskoye, Prirazlomnoye, Varandey-More and Medyn-More fields. Hydrocarbon accumulations within the offshore extension of the Pechora Platform are related to at least two petroleum systems: the Domanik-Permo-Carboniferous and the Silurian-Lower Devonian. Reservoir rocks range from the Lower Devonian to the Upper Permian and are mostly carbonates. Throughout the onshore area of the Pechora Platform, Silurian-Lower Devonian formations and Domanik shales are known as the main source rocks. This paper concerns the easternmost petroleum systems of the Pechora Platform that stretch west of the Novaya Zemlya Orogen and encompass more than 100 oil and gas fields.

PETROLEUM POTENTIAL OF THE ERINGA TROUGH IN SA AND THE NT

The Eringa Trough occupies an area of over 8,000 km2 in SA and the NT and contains an estimated 1,500 m of Permo-Carboniferous and over 1,000 m of Mesozoic sediments. Early Permian depositional history of this frontier region is similar to that of the Cooper Basin in northeastern SA. The Eringa Trough has limited seismic coverage and sparse petroleum and mineral exploration drillholes are located on the trough margins. Interpretation of 255 km of new seismic and reprocessed data has delineated a number of undrilled prospects.Excellent quality reservoirs are present. Early mature to mature, Permian and Jurassic source rocks occur, including good to excellent Type-II kerogens within an equivalent of the Jurassic Birkhead Formation. Apatite fission track analysis of Permian and Jurassic sediment shows palaeo-temperatures were approximately 30-40°C higher than at present and that cooling occurred within the last 60 Ma. This suggests that Permian and Jurassic sediments in the deeper parts of the Eringa Trough have experienced temperatures suitable for petroleum generation.An integrated evaluation of the Eringa Trough in SA and the NT has resulted in a greater understanding of this frontier area which has the potential for significant commercial petroleum discoveries.

HYDROCARBON POTENTIAL OF MANILA BAY AND ADJACENT AREAS

The first ever exploratory well in the Manila Bay sector of the Central Luzon Basin, Philippines was drilled in mid-1995. The well yielded encouraging results. Although it failed to reach its main objective between 2,900 and 3,350 m (9,500 and 11,000 feet) and was not tested due to technical problems, the drilling results provided valuable geological information which has substantially upgraded the hydrocarbon prospectivity of the area.Manila Bay 1A/1AST was drilled to a total depth of 2,265 m (7,430 feet) and penetrated an over-pressured, potentially gas-bearing Late Miocene-Pliocene carbonate reservoir between 1,995 and 2,210 m (6,546 and 7,252 feet). Gas (C1 to C4) in the mudstream while drilling and streaming cuts and fluorescence in certain samples, attest to the generative potential of the southern sector of the Central Luzon Basin. Furthermore, the results demonstrate the development of previously unrecognized excellent shelfal carbonate reservoirs on the southwestern margin of the basin.A second well in Manila Bay is planned for drilling in first quarter 1996, to fully appraise the gas potential of the Late Miocene-Pliocene carbonate section and to explore the deeper primary objective of possible Middle Miocene or older age carbonates. In parallel, exploration plans are also being drawn to confirm possible similar features in the onshore area immediately north of Manila Bay.Any commercial hydrocarbon discoveries in Manila Bay and/or this adjacent onshore area would constitute economically significant sources of indigenous energy for Metro Manila and the rapidly industrializing adjacent provinces.

AVO as an Exploration Tool in the Penola Trough, Otway Basin

In 1988, Katnook-1 discovered gas in the basal Eumeralla Formation in the Penola Trough. All subsequent commercial discoveries have been within the underlying Crayfish Group. Amplitude-versus-offset (AVO) analysis performed on single gather records correctly predicted the subsequent discovery of gas within the Crayfish Group in the Katnook-2 and Ladbroke Grove-1 wells. Seismic recorded since 1990 has generally better quality data which are more suitable for AVO analysis. Two lines were recorded in 1993 over the Katnook Field, tied to the three Katnook wells. Only a small AVO effect was predicted at some locations from modelling using the well data, which was probably due to the poor quality well logs. The seismic AVO analysis, however, using all gather records, produced clear anomalies at both reservoir levels which approximately matched the predicted extent of the gas in the field from structural mapping. The subsequent Katnook-4 appraisal well confirmed the presence of gas at these levels, but unfortunately was not commercial. AVO and inversion were also run over the Haselgrove Gas Field prior to its discovery in 1994. AVO anomalies are seen at both Katnook reservoir levels, but the strong basal Eumeralla Formation anomaly is interpreted to be due to a clean, water saturated sand rather than gas. The anomalies at the top Pretty Hill Sandstone level are more consistent with structure although they extend below mapped closure. Subsequent reprocessing using pre-stack migration prior to AVO analysis produced anomalies which closely match the actual gas column height, and are within the zone of strong seismic amplitudes at this level. AVO anomalies in the area appear to be caused by both clean, water filled sands and the presence of hydrocarbons. Seismic inversion can help the prediction of sand quality variations, and the mapped extent of structural closure can be used to identify those AVO anomalies more likely to be related to hydrocarbons. Pre-stack time migration prior to AVO processing is essential in most cases. Unfortunately, AVO anomalies also occur in reservoirs with low gas saturations or low reservoir permeability. Despite these drawbacks AVO with inversion has proven to be a valuable exploration tool in the Penola Trough. No gas discoveries have yet been made which are not associated with an AVO anomaly.

THE HYDROCARBON POTENTIAL OF THE PENOLA TROUGH, OTWAY BASIN

The Penola Trough is an elongate, Late Jurassic to Early Cretaceous, NW-SE trending half graben filled mainly with synrift sediments of the Crayfish Group. Katnook-1 discovered gas in the basal Eumeralla Formation, but all commercial discoveries have been within the Crayfish Group, particularly the Pretty Hill Formation. Recent improvements in seismic data quality, in conjunction with additional well control, have greatly improved the understanding of the stratigraphy, structure and hydrocarbon prospectivity of the trough. Strati-graphic units within the Pretty Hill Formation are now mappable seismically. The maturity of potential source rocks within these deeper units has been modelled, and the distribution and quality of potential reservoir sands at several levels within the Crayfish Group have been studied using both well and seismic data. Evaluation of the structural history of the trough, the risk of a late carbon dioxide charge to traps, the direct detection of gas using seismic AVO analysis, and the petrophysical ambiguities recorded in wells has resulted in new insights. An important new play has been recognised on the northern flank of the Penola Trough: a gas and oil charge from mature source rocks directly overlying basement into a quartzose sand sequence referred to informally as the Sawpit Sandstone. This play was successfully tested in early 1994 by Wynn-1 which flowed both oil and gas during testing from the Sawpit Sandstone. In mid 1994, Haselgrove-1 discovered commercial quantities of gas in a tilted Pretty Hill Formation fault block adjacent to the Katnook Field. These recent discoveries enhance the prospectivity of the Penola Trough and of the Early Cretaceous sequence in the wider Otway Basin where these sediments are within reach of the drill.

DEPOSITIONAL MODELS AND RESERVOIR PROPERTIES OF MIOCENE REEFS, VISAYAN ISLANDS, PHILIPPINES

Recent commercial discoveries offshore Palawan have propelled the Philippines into the list of oil‐ and gas‐producing countries, and have focussed on the importance of Miocene reefs as reservoirs. This new situation has motivated the update of earlier depositional‐diagenetic models for the Miocene reefs in the Visayan Islands, which is presented in this paper. These reefs consisted of an association of corals, red algae, bryozoans, and encrusting foraminifers, which formed wave‐resistant, constructed, barrier‐and‐atoll systems along the edge of narrow shelves, with associated back‐reef patch reefs and frontal pinnacle reefs. The latter also grew on structural and depositional highs and plaforms among deeper water carbonate mudstones and shales.Reservoirs developed in all the various types of buildups by extensive burial dissolution, often preceded (with the exception of some pinnacle reefs) by subaerial exposure generating secondary porosity by vadose to phreatic undersaturated dissolution. Seals were generally provided by overlying basinal carbonate mudstones and shales, and by andesitic volcaniclastics and basaltic lava flows. Source beds were mature, basinal, bituminous carbonate mudstones and shales, and migration of hydrocarbons was mainly updip, complicated by local structural conditions.

THE HYDROCARBON POTENTIAL OF THE PALAEOZOIC BASINS OF WESTERN AUSTRALIA

There are four main Palaeozoic Basins in Western Australia; the Perth Basin (Permian only), the Carnarvon Basin (Ordovician-Permian), the Canning Basin (Ordovician-Permian) and the Bonaparte Basin (Cambrian-Permian).The Perth Basin is a proven petroleum province with commercially producing gas reserves from Permian strata in the Dongara, Woodada and Beharra Springs gas fields.The Palaeozoic of the Carnarvon Basin occurs in three main sub-basins, the Ashburton, Merlinleigh and Gascoyne Sub-basins. No commercial petroleum discoveries ahve been made in these basins.The Canning Basin can be divided into the southern Ordovician-Devonian province of the Willara and Kidson sub-basins and Wallal Embayment and Anketell Shelf, and the northern Devonian-Permian province of the Fitzroy and Gregory sub-basins. Commercial production from the Permo-Carboniferous Sundown, Lloyd, West Terrace, Boundary oilfields and from the Devonian Blina oilfield is present only in the Fitzroy sub-basins.The Bonaparte Basin contains Palaeozoic strata of Cambrian-Permian age but only the Devonian-Permian is considered prospective. Significant but currently non-producing gas discoveries have been made in the Permian of the Petrel and Tern offshore gas fields.Based on the current limited well control, the Palaeozoic basins of Western Australia contain excellent marine and non marine clastic reservoirs together with potential Upper Devonian and Lower Carboniferous reefs. The dominantly marine nature of the Palaeozoic provides thick marine shale seals for these reservoirs. Source rock data is very sparse but indicates excellent gas prone source rocks in the Early Permian and excellent—good oil prone source rocks in the Early Ordovician, Late Devonian, Early Carboniferous and Late Permian.Many large structures are present in these Palaeozoic basins. However, most of the existing wells were drilled either off structure due to insufficient and poor quality seismic or on structures formed during the Mesozoic which postdated primary hydrocarbon migration from the Palaeozoic source rocks.With modern seismic acquisition and processing techniques together with a better understanding of the stratigraphy, structural development and hydrocarbon migration, the Palaeozoic basins of Western Australia provide the explorer with a variety of high risk, high potential plays without the intense bidding competition currently present along the North West Shelf of Australia.

Aspects of the petroleum geology of the Oriente Basin, Ecuador

Abstract The Oriente Basin of Ecuador is one of the most productive of the South American Sub-Andean Basins. Cumulative production of oil to the end of 1986 was over one billion barrels, and current production stands at approximately 300 000 barrels per day. At least 20 oil fields have been discovered to date, including five giant fields, and exploration is currently in the early stages of a new and already successful phase in which ten new operators are scheduled to drill over 40 wells between 1985 and 1992. The Oriente Basin contains a sedimentary fill of Palaeozoic to Recent age. Major commercial interest is confined to the Cretaceous depositional cycle and all of the significant production comes from fluvio-deltaic and marine sandstones of the Hollin and Napo Formations. Most of the productive structures are low-relief, north-south orientated, anticlines of two distinct types: foot wall anticlines associated with normal faults, (Type 1) or hanging wall anticlines associated with reverse faults, (Type 2). Evidence points to the importance of pre-Miocene structural growth, comprising either early-mid Cretaceous rejuvenation of pre-Cretaceous ‘basement’ faults in the case of Type-1 structures and ‘Early Andean’ (latest Cretaceous to Oligocene) compression in the case of Type-2 structures. Few commercial discoveries have been made associated with ‘Late Andean’ (Miocene-Pliocene) compressional structures, essentially because these structures appear to post-date the main phase of primary oil generation and migration. The origin of the oils is problematical because the potential source rocks, the marine claystones and limestones of the Cretaceous Napo Formation, are generally immature or marginally mature within the confines of the present-day Oriente Basin. Oil analyses indicate a single family of oils. Available evidence, combined from structural and geochemical data, supports a major phase of Early Andean age oil generation and migration. There is a considerable variation of oil type from 37° API paraffinic oils with a GOR of 250–300 to altered 10° API oils. Marked variations exist not only between oilfields but also between reservoirs in the same well. The observed trends can in most cases be accounted for systematically in terms of: early primary oil generation, migration and entrapment; and subsequent structural evolution locally involving the processes of biodegration, water washing and/or flushing, and oil remigration.

THE LANDER TROUGH—A CENTRAL AUSTRALIAN FRONTIER EXPLORATION AREA

The Lander Trough is an almost unexplored area of 30 000 square kilometres in the central western Northern Territory. It has very similar stratigraphy and structural features to the nearby Amadeus, Ngalia and southern Georgina Basins. They all contain fluvio-deltaic to marine sediments of Late Proterozoic to Carboniferous age and were subjected to deformation during several major periods of folding and overthrusting. They are remnants of one depositional basin which covered much of Northern Australia in the Late Proterozoic and Early Palaeozoic Eras. Producing oil and gas fields occur in the Amadeus Basin and there are many oil and gas occurrences in the southern Georgina and Ngalia Basins. The Lander Trough contains up to 3000 metres of largely marine clastic and carbonate sediments which are expected to include mature source rocks and effective reservoirs and seals. Adequate migration paths and trapping mechanisms are believed to be present. The Lander Trough has the potential for commercial petroleum discoveries.

THE GEOLOGY AND PETROLEUM POTENTIAL OF THE WESTERN ARAFURA SEA

The northern Bonaparte Basin and the Arafura-Money Shoal Basins lie along Australia's offshore northern margin and offer significantly different exploration prospects resulting from their differing tectonic and burial histories. The Arafura Basin is dominated by a deep, faulted and folded, NW-SE orientated Palaeozoic graben overlain by the relatively flat-lying Jurassic-Tertiary Money Shoal Basin. The north-eastern Bonaparte Basin is dominated by the deep NE-SW orientated Malita Graben with mainly Jurassic to Recent basin-fill.A variety of potential structural and stratigraphic traps occur in the region especially associated with the grabens. They include tilted or horst fault blocks and large compressional, drape and rollover anticlines. Some inversion and possibly interference anticlines result from late Cenozoic collision between the Australian plate and Timor and the Banda Arc.In the Arafura-Money Shoal Basins, good petroleum source rocks occur in the Cambrian, Carboniferous and Jurassic-Cretaceous sequences although maturation is biassed towards early graben development. Jurassic-Neocomian sandstones have the best reservoir potential, Carboniferous clastics offer moderate prospects, and Palaeozoic carbonates require porosity enhancement.The Malita Graben probably contains good potential Jurassic source rocks which commenced generation in the Late Cretaceous. Deep burial in the graben has decreased porosity of the Jurassic-Neocomian sandstones significantly but potential reservoirs may occur on the shallower flanks.The region is sparsely explored and no commercial discoveries exist. However, oil and gas indications are common in a variety of Palaeozoic and Mesozoic sequences and structural settings. These provide sufficient encouragement for a new round of exploration.

THE SIGNIFICANCE OF HYDROCARBON SHOWS AND OIL RECOVERIES IN THE LONGREACH AREA, CENTRAL QUEENSLAND

In 1925, over 40 gallons of oil were recovered from the Longreach town- water well. More recently, Corona 1, drilled by the ATP 271P Joint Venture in 1984, recovered 9 m (0.5 bbls) of oil in the drill pipe.These oil recoveries, along with several water- bore oil and gas occurrences, are all located in the Longreach area, Central Queensland, over 100 km north- northeast of the Cooper Basin zero edge. The oil recoveries and shows are therefore considered to be the product of source rocks other than those of the Cooper Basin.The Birkhead Formation, the unit considered most likely to source the Longreach and Corona oils, has been studied with a view to understanding the nature of hydrocarbon generation in the vicinity of the Maneroo Platform. The variables measured include (1) thickness of the shale units, (2) volume and type of dispersed organic matter (DOM) and (3) maturity (vitrinite reflectance). Measurements were taken from 10 exploration wells through the whole formation to provide uniform comparative assessment.The Birkhead Formation in the Maneroo Platform area is shown to have an anomalously low sandstone- to- shale ratio, vitrinite reflectance values (Rm(o)) consistently greater than 0.7 per cent and a favourable petroleum generative geochemistry.These results emphasise the highly variable nature of the Eromanga Basin sequence, and therefore its diverse generative potential, and highlight the encouraging prospectivity of the Maneroo Platform area despite the present lack of commercial oil discoveries.

Integrated Exploration Method Used in Search for Stratigraphic Traps in Illinois Basin: ABSTRACT

A new oil pool was discovered in Marion County, Illinois, during 1988, using this integrated approach. The discovery is within 2.5 mi of the Salem field, which was discovered in 1938 and has produced more than 387 million bbl of oil. Numerous seismic surveys have been conducted in the area since the Salem field discovery over 50 years ago. Using structure maps developed from the available seismic data, well control, and depositional models, a Ste. Genevieve (middle Mississippian Valmeyeran) prospect was developed on the northeast flank of the Salem anticline. The initial well encountered 8 ft of oil-saturated oolitic limestone in the McClosky zone of the Ste. Genevieve Limestone. Subsequent drilling resulted in four additional oil wells. The size of the reservoir is approximately 120 ac with primary recovery estimated at 200,000 bbl of oil. The depth of the reservoir is 2,250 ft, with an average porosity of 14% and permeability of 300 md. The trapping mechanism is stratigraphic - an oolite bar draped across a gentle nose, which was originally interpreted from the seismic information. Numerous analogous situations exist in the Salem anticline area as well as near other large structures in the basin. An integrated exploration approach canmore » help define these areas and lead to commercial discoveries in mature areas.« less

Lognormal field size distributions as a consequence of economic truncation

The assumption of lognormal (parent) field size distributions has for a long time been applied to resource appraisal and evaluation of exploration strategy by the petroleum industry. However, frequency distributions estimated with observed data and used to justify this hypotheses are conditional. Examination of various observed field size distributions across basins and over time shows that such distributions should be regarded as the end result of an economic filtering process. Commercial discoveries depend on oil and gas prices and field development costs. Some new fields are eliminated due to location, depths, or water depths. This filtering process is called economic truncation. Economic truncation may occur when predictions of a discovery process are passed through an economic appraisal model. We demonstrate that (1) economic resource appraisals, (2) forecasts of levels of petroleum industry activity, and (3) expected benefits of developing and implementing cost reducing technology are sensitive to assumptions made about the nature of that portion of (parent) field size distribution subject to economic truncation.

Economics and Appraisal of Conventional Oil and Gas in the Western Gulf of Mexico

Economics and Appraisal of Conventional Oil and Gas in the Western Gulf of Mexico